EX-99.3 4 d714648dex993.htm EX-99.3

Exhibit 99.3

EMERA INCORPORATED

Consolidated

Financial Statements

December 31, 2018 and 2017

1

MANAGEMENT REPORT

Management’s Responsibility for Financial Reporting

The accompanying consolidated financial statements of Emera Incorporated and the information in this annual report are the responsibility of management and have been approved by the Board of Directors (“Board”).

The consolidated financial statements have been prepared by management in accordance with United States Generally Accepted Accounting Principles. When alternative accounting methods exist, management has chosen those it considers most appropriate in the circumstances. In preparation of these consolidated financial statements, estimates are sometimes necessary when transactions affecting the current accounting period cannot be finalized with certainty until future periods. Management represents that such estimates, which have been properly reflected in the accompanying consolidated financial statements, are based on careful judgements and are within reasonable limits of materiality. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects. Management has prepared the financial information presented elsewhere in the annual report and has ensured that it is consistent with that in the consolidated financial statements.

Emera Incorporated maintains effective systems of internal accounting and administrative controls, consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the financial information is reliable and accurate, and that Emera Incorporated’s assets are appropriately accounted for and adequately safeguarded.

The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting and is ultimately responsible for reviewing and approving the consolidated financial statements. The Board carries out this responsibility principally through its Audit Committee.

The Audit Committee is appointed by the Board, and its members are directors who are not officers or employees of Emera Incorporated. The Audit Committee meets periodically with management, as well as with the internal auditors and with the external auditors, to discuss internal controls over the financial reporting process, auditing matters and financial reporting issues, to satisfy itself that each party is properly discharging its responsibilities, and to review the annual report, the consolidated financial statements and the external auditors’ report. The Audit Committee reports its findings to the Board for consideration when approving the consolidated financial statements for issuance to the shareholders. The Audit Committee also considers, for review by the Board and approval by the shareholders, the appointment of the external auditors.

The consolidated financial statements have been audited by Ernst & Young LLP, the external auditors, in accordance with Canadian Generally Accepted Auditing Standards and with the standards of the Public Company Accounting Oversight Board. Ernst & Young LLP has full and free access to the Audit Committee.

February 15, 2019

“Scott Balfour” |  | “Gregory Blunden”
President and Chief Executive Officer |  | Chief Financial Officer

2

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Emera Incorporated

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Emera Incorporated (the “Company“) as of December 31, 2018, the related consolidated statement of income, consolidated statement of comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the year then ended, and the related notes and schedules (collectively referred to as the “consolidated financial statements“). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2018, and the consolidated results of its operations and its consolidated cash flows for the year then ended, in conformity with United States generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company‘s management. Our responsibility is to express an opinion on the Company‘s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

Ernst & Young LLP

We have served as the Company‘s auditor since 1998.

Halifax, Canada

February 15, 2019

3

INDEPENDENT AUDITORS’ REPORT

To the Shareholders and the Board of Directors of Emera Incorporated

We have audited the accompanying consolidated financial statements of Emera Incorporated, which comprise the consolidated balance sheet as at December 31, 2017, and the consolidated statements of income, comprehensive income, cash flows and changes in equity for the year then ended, and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with United States generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audit is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Emera Incorporated as at December 31, 2017, and its financial performance and its cash flows for the year then ended in accordance with United States generally accepted accounting principles.

/s/ Ernst & Young LLP

Halifax, Canada

February 9, 2018

4

Emera Incorporated

Consolidated Statements of Income

For the |  | Year ended December 31 |
millions of Canadian dollars (except per share amounts) |  | 2018 |  |  | 2017 |
Operating revenues |  |  |  |  |  |  |  |
Regulated electric |  | $ | 4,852 |  |  | $ | 4,721 |
Regulated gas |  |  | 1,044 |  |  |  | 1,002 |
Non-regulated |  |  | 628 |  |  |  | 503 |
Total operating revenues (note 5) |  |  | 6,524 |  |  |  | 6,226 |
Operating expenses |  |  |  |  |  |  |  |
Regulated fuel for generation and purchased power |  |  | 1,677 |  |  |  | 1,638 |
Regulated cost of natural gas |  |  | 388 |  |  |  | 379 |
Non-regulated fuel for generation and purchased power |  |  | 225 |  |  |  | 209 |
Non-regulated direct costs |  |  | 16 |  |  |  | 28 |
Operating, maintenance and general |  |  | 1,564 |  |  |  | 1,372 |
Provincial, state, and municipal taxes |  |  | 340 |  |  |  | 326 |
Depreciation and amortization |  |  | 916 |  |  |  | 856 |
Total operating expenses |  |  | 5,126 |  |  |  | 4,808 |
Income from operations |  |  | 1,398 |  |  |  | 1,418 |
Income from equity investments (note 6) |  |  | 154 |  |  |  | 124 |
Other expenses, net |  |  | 23 |  |  |  | 25 |
Interest expense, net |  |  | 713 |  |  |  | 698 |
Income before provision for income taxes |  |  | 816 |  |  |  | 819 |
Income tax expense (note 7) |  |  | 69 |  |  |  | 520 |
Net income |  |  | 747 |  |  |  | 299 |
Non-controlling interest in subsidiaries |  |  | 1 |  |  |  | 5 |
Preferred stock dividends |  |  | 36 |  |  |  | 28 |
Net income attributable to common shareholders |  | $ | 710 |  |  | $ | 266 |
Weighted average shares of common stock outstanding (in millions)(note 9) |  |  |  |  |  |  |  |
Basic |  |  | 233 |  |  |  | 213 |
Diluted |  |  | 234 |  |  |  | 214 |
Earnings per common share (note 9) |  |  |  |  |  |  |  |
Basic |  | $ | 3.05 |  |  | $ | 1.25 |
Diluted |  | $ | 3.04 |  |  | $ | 1.24 |
Dividends per common share declared |  | $ | 2.2825 |  |  | $ | 2.1325 |
The accompanying notes are an integral part of these consolidated financial statements. |

5

Emera Incorporated

Consolidated Statements of Comprehensive Income

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2018 |  |  | 2017 |
Net income |  | $ | 747 |  |  | $ | 299 |
Other comprehensive income (loss), net of tax |  |  |  |  |  |  |  |
Foreign currency translation adjustment |  |  | 627 |  |  |  | (464) |
Unrealized gains (losses) on net investment hedges (1) (2) |  |  | (122) |  |  |  | 97 |
Cash flow hedges |  |  |  |  |  |  |  |
Net derivative gains (losses) |  |  | 2 |  |  |  | 10 |
Less: reclassification adjustment for losses (gains) included in income (3) |  |  | (6) |  |  |  | 8 |
Net effects of cash flow hedges |  |  | (4) |  |  |  | 18 |
Unrealized gains on available-for-sale investment |  |  |  |  |  |  |  |
Unrealized gain (loss) arising during the period |  |  | - |  |  |  | 5 |
Less: reclassification adjustment for (gains) recognized in income |  |  | (4) |  |  |  | (1) |
Net unrealized holding gains (losses) |  |  | (4) |  |  |  | 4 |
Net change in unrecognized pension and post-retirement benefit obligation (4) |  |  | 9 |  |  |  | 40 |
Other comprehensive income (loss) (5) |  |  | 506 |  |  |  | (305) |
Comprehensive income (loss) |  |  | 1,253 |  |  |  | (6) |
Comprehensive income (loss) attributable to non-controlling interest |  |  | 4 |  |  |  | - |
Comprehensive Income (loss) of Emera Incorporated |  | $ | 1,249 |  |  | $ | (6) |

The accompanying notes are an integral part of these consolidated financial statements.

1) The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations.

2) Net of tax recovery of $9 million (2017 - $9 million tax expense) for the year ended December 31, 2018.

3) Net of tax recovery of nil (2017 - $1 million tax recovery) for the year ended December 31, 2018.

4) Net of tax recovery of $2 million (2017 - $4 million tax recovery) for the year ended December 31, 2018.

5) Net of tax recovery of $11 million (2017 - $4 million tax expense) for the year ended December 31, 2018.

6

Emera Incorporated

Consolidated Balance Sheets

As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |
Assets |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 316 |  |  | $ | 438 |
Restricted cash (note 1) |  |  | 56 |  |  |  | 65 |
Inventory (note 11) |  |  | 474 |  |  |  | 418 |
Derivative instruments (notes 12 and 13) |  |  | 148 |  |  |  | 141 |
Regulatory assets (note 14) |  |  | 165 |  |  |  | 138 |
Receivables and other current assets (note 16) |  |  | 1,620 |  |  |  | 1,326 |
Assets held for sale (note 17) |  |  | 53 |  |  |  | - |
|  |  | 2,832 |  |  |  | 2,526 |
Property, plant and equipment, net of accumulated depreciation and amortization of $8,567 and $7,824, respectively (note 18) |  |  | 18,712 |  |  |  | 16,995 |
Other assets |  |  |  |  |  |  |  |
Deferred income taxes (note 7) |  |  | 175 |  |  |  | 138 |
Derivative instruments (notes 12 and 13) |  |  | 19 |  |  |  | 112 |
Regulatory assets (note 14) |  |  | 1,404 |  |  |  | 1,273 |
Net investment in direct financing lease (note 20) |  |  | 475 |  |  |  | 481 |
Investments subject to significant influence (note 6) |  |  | 1,316 |  |  |  | 1,215 |
Goodwill (note 21) |  |  | 6,313 |  |  |  | 5,805 |
Other long-term assets |  |  | 291 |  |  |  | 261 |
Assets held for sale (note 17) |  |  | 777 |  |  |  | - |
|  |  | 10,770 |  |  |  | 9,285 |
Total assets |  | $ | 32,314 |  |  | $ | 28,806 |

7

Emera Incorporated

Consolidated Balance Sheets – Continued

As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |
Liabilities and Equity |
Current liabilities |  |  |  |  |  |  |  |
Short-term debt (note 22) |  | $ | 1,186 |  |  | $ | 1,241 |
Current portion of long-term debt (note 24) |  |  | 1,119 |  |  |  | 741 |
Accounts payable |  |  | 1,289 |  |  |  | 1,161 |
Derivative instruments (notes 12 and 13) |  |  | 260 |  |  |  | 227 |
Regulatory liabilities (note 14) |  |  | 251 |  |  |  | 226 |
Other current liabilities (note 23) |  |  | 428 |  |  |  | 350 |
Liabilities associated with assets held for sale (note 17) |  |  | 20 |  |  |  | - |
|  |  | 4,553 |  |  |  | 3,946 |
Long-term liabilities |  |  |  |  |  |  |  |
Long-term debt (note 24) |  |  | 14,292 |  |  |  | 13,140 |
Deferred income taxes (note 7) |  |  | 1,320 |  |  |  | 1,023 |
Derivative instruments (notes 12 and 13) |  |  | 105 |  |  |  | 83 |
Regulatory liabilities (note 14) |  |  | 2,359 |  |  |  | 2,242 |
Pension and post-retirement liabilities (note 19) |  |  | 641 |  |  |  | 559 |
Other long-term liabilities (note 6 and 25) |  |  | 686 |  |  |  | 609 |
|  |  | 19,403 |  |  |  | 17,656 |
Commitments and contingencies (note 26) |  |  |  |  |  |  |  |
Equity |  |  |  |  |  |  |  |
Common stock (note 8) |  |  | 5,816 |  |  |  | 5,601 |
Cumulative preferred stock (note 27) |  |  | 1,004 |  |  |  | 709 |
Contributed surplus |  |  | 84 |  |  |  | 76 |
Accumulated other comprehensive income (loss) (note 10) |  |  | 338 |  |  |  | (165) |
Retained earnings |  |  | 1,075 |  |  |  | 891 |
Total Emera Incorporated equity |  |  | 8,317 |  |  |  | 7,112 |
Non-controlling interest in subsidiaries (note 28) |  |  | 41 |  |  |  | 92 |
Total equity |  |  | 8,358 |  |  |  | 7,204 |
Total liabilities and equity |  | $ | 32,314 |  |  | $ | 28,806 |

The accompanying notes are an integral part of these consolidated financial statements.

Approved on behalf of the Board of Directors

“M. Jacqueline Sheppard” |  | “Scott Balfour”
Chair of the Board |  | President and Chief Executive Officer

8

Emera Incorporated

Consolidated Statements of Cash Flows

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2018 |  |  | 2017 |
Operating activities |  |  |  |  |  |  |  |
Net income |  | $ | 747 |  |  | $ | 299 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 928 |  |  |  | 851 |
Income from equity investments, net of dividends |  |  | (75) |  |  |  | (90) |
Allowance for equity funds used during construction |  |  | (19) |  |  |  | (9) |
Deferred income taxes, net (1) |  |  | 185 |  |  |  | 469 |
Net change in pension and post-retirement liabilities |  |  | 11 |  |  |  | (12) |
Regulated fuel adjustment mechanism |  |  | (16) |  |  |  | 68 |
Net change in fair value of derivative instruments |  |  | 55 |  |  |  | (157) |
Net change in regulatory assets and liabilities (2) |  |  | 51 |  |  |  | (237) |
Net change in capitalized transportation capacity |  |  | (105) |  |  |  | 84 |
Other operating activities, net |  |  | 44 |  |  |  | 31 |
Changes in non-cash working capital (note 29) |  |  | (116) |  |  |  | (104) |
Net cash provided by operating activities |  |  | 1,690 |  |  |  | 1,193 |
Investing activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (2,162) |  |  |  | (1,529) |
Net purchase of investments subject to significant influence, inclusive of acquisition costs |  |  | (49) |  |  |  | (213) |
Other investing activities |  |  | 21 |  |  |  | (19) |
Net cash used in investing activities |  |  | (2,190) |  |  |  | (1,761) |
Financing activities |  |  |  |  |  |  |  |
Change in short-term debt, net |  |  | 99 |  |  |  | (31) |
Proceeds from short-term debt with maturities greater than 90 days |  |  | 129 |  |  |  | 383 |
Repayment of short-term debt with maturities greater than 90 days |  |  | (390) |  |  |  | - |
Proceeds from long-term debt, net of issuance costs |  |  | 1,055 |  |  |  | 129 |
Retirement of long-term debt |  |  | (757) |  |  |  | (453) |
Net borrowings (repayments) under committed credit facilities |  |  | 321 |  |  |  | 230 |
Issuance of common stock, net of issuance costs |  |  | 10 |  |  |  | 682 |
Issuance of preferred stock, net of issuance costs (note 27) |  |  | 291 |  |  |  | - |
Dividends on common stock |  |  | (346) |  |  |  | (287) |
Dividends on preferred stock |  |  | (36) |  |  |  | (28) |
Other financing activities |  |  | (32) |  |  |  | (32) |
Net cash provided by financing activities |  |  | 344 |  |  |  | 593 |
Effect of exchange rate changes on cash, cash equivalents, and restricted cash |  |  | 25 |  |  |  | (13) |
Net increase (decrease) in cash, cash equivalents, and restricted cash |  |  | (131) |  |  |  | 12 |
Cash, cash equivalents, and restricted cash, beginning of year |  |  | 503 |  |  |  | 491 |
Cash, cash equivalents and restricted cash, end of year |  |  | 372 |  |  |  | 503 |
Cash, cash equivalents, and restricted cash consists of: |  |  |  |  |  |  |  |
Cash |  |  | 273 |  |  |  | 216 |
Short-term investments |  |  | 43 |  |  |  | 222 |
Restricted cash |  |  | 56 |  |  |  | 65 |
Cash, cash equivalents, and restricted cash |  |  | 372 |  |  |  | 503 |

(1) 2017 includes $317 million for the revaluation of US non-regulated net deferred income tax assets as a result of US tax reform.

(2) 2017 includes the net impact of the change in deferred taxes as a result of US tax reform with an offset to a regulatory liability of $1.1 billion.

Supplementary Information to Consolidated Statements of Cash Flows (note 29)

The accompanying notes are an integral part of these consolidated financial statements.

9

Emera Incorporated

Consolidated Statements of Changes in Equity

|  | Common Stock |  |  | Preferred Stock |  |  | Contributed Surplus |  |  | Accumulated Other Comprehensive Income (Loss) (1) |  |  | Retained Earnings |  |  | Non- Controlling Interest |  |  | Total Equity |
millions of Canadian dollars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance, December 31, 2017 |  | $ | 5,601 |  |  | $ | 709 |  |  | $ | 76 |  |  | $ | (165) |  |  | $ | 891 |  |  | $ | 92 |  |  | $ | 7,204 |
Net income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 746 |  |  |  | 1 |  |  |  | 747 |
Other comprehensive income, net of tax recovery of $11 million |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 503 |  |  |  | - |  |  |  | 3 |  |  |  | 506 |
Issuance of preferred stock, net of after-tax issuance costs |  |  | - |  |  |  | 295 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 295 |
Dividends declared on preferred stock (note 27) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (36) |  |  |  | - |  |  |  | (36) |
Dividends declared on common stock ($2.2825/share) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (528) |  |  |  | - |  |  |  | (528) |
Common stock issued under purchase plan |  |  | 191 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 191 |
Acquisition of non-controlling interest of ICD Utilities Limited (“ICDU”) |  |  | 22 |  |  |  | - |  |  |  | 6 |  |  |  | - |  |  |  | - |  |  |  | (53) |  |  |  | (25) |
Other |  |  | 2 |  |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |  |  |  | (2) |  |  |  | 4 |
Balance, December 31, 2018 |  | $ | 5,816 |  |  | $ | 1,004 |  |  | $ | 84 |  |  | $ | 338 |  |  | $ | 1,075 |  |  | $ | 41 |  |  | $ | 8,358 |
Balance, December 31, 2016 |  | $ | 4,738 |  |  | $ | 709 |  |  | $ | 75 |  |  | $ | 135 |  |  | $ | 1,076 |  |  | $ | 112 |  |  | $ | 6,845 |
Net income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 294 |  |  |  | 5 |  |  |  | 299 |
Other comprehensive income (loss), net of tax expense of $4 million |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (300) |  |  |  | - |  |  |  | (5) |  |  |  | (305) |
Issuance of common stock, net of after-tax issuance costs |  |  | 686 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 686 |
Dividends declared on preferred stock (note 27) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (28) |  |  |  | - |  |  |  | (28) |
Dividends declared on common stock ($2.1325/share) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (451) |  |  |  | - |  |  |  | (451) |
Common stock issued under purchase plan |  |  | 173 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 173 |
Stock-based compensation |  |  | 3 |  |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 4 |
Repurchase of preferred shares of GBPC (note 28) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (14) |  |  |  | (14) |
Other |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (6) |  |  |  | (5) |
Balance, December 31, 2017 |  | $ | 5,601 |  |  | $ | 709 |  |  | $ | 76 |  |  | $ | (165) |  |  | $ | 891 |  |  | $ | 92 |  |  | $ | 7,204 |

(1) Accumulated Other Comprehensive Income (Loss) (“AOCI”) (“AOCL”)

The accompanying notes are an integral part of these consolidated financial statements.

10

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2018 and 2017

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution and gas transmission and distribution.

At December 31, 2018, Emera’s primary rate-regulated subsidiaries and investments included the following:

| ● | Emera Florida and New Mexico represents TECO Energy, Inc. (“TECO Energy”), a holding company with regulated electric and gas utilities in Florida and New Mexico that include:

| ● | Tampa Electric Company (“TEC”), which holds the Tampa Electric Division (“Tampa Electric”), a vertically integrated regulated electric utility, serving approximately 764,000 customers in West Central Florida, and Peoples Gas System Division (“PGS”), a regulated gas distribution utility, serving approximately 392,000 customers across Florida;

| ● | New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 530,000 customers across New Mexico;

| ● | TECO Finance, Inc. (“TECO Finance”), a financing subsidiary of TECO Energy; and

| ● | SeaCoast Gas Transmission LLC (“SeaCoast”), a regulated intrastate natural gas transmission company offering services in Florida.

| ● | Nova Scotia Power Inc. (“NSPI”), a vertically integrated regulated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 519,000 customers;

| ● | Emera Maine, a regulated electric transmission and distribution utility, serving approximately 159,000 customers in the state of Maine;

| ● | Emera Caribbean represents Emera (Caribbean) Incorporated (“ECI”), a holding company with regulated electric utilities that include:

| ● | The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados, serving approximately 130,000 customers;

| ● | Grand Bahama Power Company Limited (“GBPC”), a vertically integrated utility operating on Grand Bahama Island, serving approximately 19,000 customers. On January 15, 2018, Emera completed the acquisition of the minority shareholder common shares for total consideration of $35 million USD, increasing Emera’s interest in GBPC from 80.4 per cent to 100 per cent;

| ● | a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), a vertically integrated utility on the island of Dominica, serving approximately 26,000 customers; and

| ● | a 19.1 per cent indirect interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia.

| ● | Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145-kilometre pipeline delivering re-gasified liquefied natural gas (“LNG”) from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada, which expires in 2034;

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| ● | Emera Newfoundland & Labrador Holdings Inc. (“ENL”), consisting of two transmission investments related to an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador being developed by Nalcor Energy and forecasted to be generating first power in 2019 and full power in 2020. ENL’s two investments are:

| ● | a 100 per cent investment in NSP Maritime Link Inc. (“NSPML”), which developed the Maritime Link Project, a $1.56 billion transmission project, including two 170-kilometre subsea cables, connecting the island of Newfoundland and Nova Scotia. This project went in service on January 15, 2018; and

| ● | a 49.5 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Construction of the LIL has been completed and the energization phase of the project began in June 2018.

| ● | a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States.

At December 31, 2018, Emera’s investments in other energy-related non-regulated companies included the following:

| ● | Emera Energy, which consists of:

| ● | Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services;

| ● | Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities” or “NEGG”), 1,115 MW of combined-cycle gas-fired electricity generating capacity in the northeastern United States. On November 26, 2018, Emera announced an agreement to sell its NEGG facilities. The transaction is expected to close in the first quarter of 2019. Refer to note 17 for additional information;

| ● | Bayside Power Limited Partnership (“Bayside Power”), a 290 MW gas-fired combined cycle power plant in Saint John, New Brunswick;

| ● | Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI; and

| ● | a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

| ● | Emera Reinsurance Limited, a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost efficient management of risk and deductible levels across Emera;

| ● | Emera US Finance LP, a wholly owned financing subsidiary of Emera;

| ● | Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States;

| ● | Emera Utility Services Inc., a utility services contractor primarily operating in Atlantic Canada; and

| ● | other investments.

Basis of Presentation

These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). In the opinion of management, these consolidated financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera.

All dollar amounts are presented in Canadian dollars, unless otherwise indicated.

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Principles of Consolidation

The consolidated financial statements of Emera include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for variable interest entities in which Emera is not the primary beneficiary.

The Company performs ongoing analysis to assess whether it holds any VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity.

Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues. An offset is recorded to property, plant and equipment, regulatory assets, regulated fuel for generation and purchased power, or operating, maintenance and general (“OM&G”), depending on the nature of the transaction.

Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect the reported amounts of assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Actual results may differ significantly from these estimates.

Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an independent third-party regulator. The rates are designed to recover the costs of providing the regulated products or services and provide a reasonable rate of return on the equity invested or assets as applicable (refer to note 14 for additional details).

Foreign Currency Translation

Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at the rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income.

Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI.

The Company designates certain United States dollar denominated debt held in Canadian dollar functional currency companies as hedges of net investments in United States dollar denominated foreign operations. The change in the carrying amount of these investments, measured at the exchange rates in effect at the balance sheet date, and the effective portion of the hedge, is recorded in Other Comprehensive Income (“OCI”). Any ineffectiveness is reflected in current period earnings.

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Revenue Recognition

Regulated electric revenue

Electric revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the electricity. Electric revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of megawatt hour (“MWh”) delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-period changes to customer classes.

Regulated gas revenue

Gas revenues, including energy charges, demand charges, basic facilities charges and applicable clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when gas is delivered to customers over time as the customer simultaneously receives and consumes the benefits of the gas. Gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the distribution and sale of gas are recognized at rates approved by the respective regulator and recorded based on metered usage, which occur on a periodic, systematic basis, generally monthly. At the end of each reporting period, the gas delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the number of therms delivered to customers at the established rate expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of usage, weather, and inter-period changes to customer classes.

Direct Finance Lease

The Company records the net investment in a lease under the direct finance method for Emera Brunswick Pipeline, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” on the Consolidated Statements of Income.

Non-regulated revenue

Marketing and trading margin is comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under terms of a contract are satisfied and are presented on a net basis, reflecting the nature of the contractual relationships with customers and suppliers.

Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time.

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Capacity payments are recognized when obligations under the terms of a contract are satisfied, which is as the plants stand ready to deliver electricity to customers. Revenues related to capacity payments are recognized at rates determined through an auction process held annually, three years in advance, through the forward capacity market.

Other non-regulated revenues are recorded when obligations under terms of a contract are satisfied.

Other

Sales, value add, and other taxes, with the exception of gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue.

Franchise Fees and Gross Receipts

Tampa Electric and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income.

Property, Plant and Equipment

Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of contributions received in aid of construction.

The cost of additions, including betterments and replacements of units of property, plant and equipment are included in “Property, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions occur.

The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, asset retirement obligations (“ARO”) and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit.

Normal maintenance projects are expensed as incurred. Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized.

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Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of depreciable property. For some of Emera’s rate regulated subsidiaries depreciation is calculated using the group remaining life method which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require the appropriate regulatory approval.

Intangible assets, which are included in “Property, plant and equipment” consist primarily of computer software, land rights and naming rights with definite lives. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate regulated subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. The service lives of regulated intangible assets require regulatory approval.

Goodwill

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange. Under the applicable accounting guidance, goodwill is subject to an annual assessment for impairment at the reporting unit level. Refer to note 21 for further detail.

Income Taxes and Investment Tax Credits

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and historical information, including forward-looking information, and the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded at the amount expected to be realized.

Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned by Tampa Electric, PGS, NMGC and Emera Maine on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by the regulatory practices.

Emera’s rate-regulated subsidiaries recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future rates, unless specifically directed by a regulator to flow deferred income taxes through earnings. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets.

Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. Refer to note 7 for further details.

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Derivatives and Hedging Activities

The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as held-for-trading (“HFT”). Collectively, these contracts and financial instruments are considered derivatives.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period. Where the documentation or effectiveness requirements are not met any changes in fair value are recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by Tampa Electric, PGS, NMGC, NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates.

Derivatives that do not meet any of the above criteria are designated as HFT, with changes in fair value normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory and property, operating maintenance and general and plant and equipment, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of marketing and trading transactions is recognized as an asset in “Other” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows.

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”.

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Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. Total short-term investments of $43 million have an effective interest rate of 2.0 per cent at December 31, 2018 (2017 - $222 million with an effective interest rate of 1.4 per cent).

Included in restricted cash are funds required to be set aside for the BLPC Self-Insurance Fund (“SIF”) (note 31).

Receivables and Allowance for Doubtful Accounts

Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit risk assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis.

Management estimates uncollectible accounts receivable after considering historical loss experience, customer deposits, current events and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.

Inventory

Fuel and materials inventories are valued using the weighted-average cost method. These inventories are carried at the lower of weighted-average cost or net realizable value, unless evidence indicates that the weighted-average cost will be recovered in future customer rates.

Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purchased, or allocated by the respective government agency.

Asset Impairment

Long-Lived Assets

Emera assesses whether there has been an impairment of long-lived assets and intangibles when such indicators exist. The Company reviews all long-lived assets in the last quarter of each year to ensure that any gradual change over the year and the seasonality of the markets are considered when determining which assets require an impairment analysis. In the case of a triggering event, such as a significant market disruption or sale of a business, the values of related long-lived assets are reviewed outside of this annual analysis.

The review of long-lived assets for impairment involves comparing the undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its estimated fair value. The Company’s assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which give consideration to external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.

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Goodwill

Goodwill is not amortized, but is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level. Reporting units with similar characteristics are grouped for the purpose of determining impairment, if any, of goodwill. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance.

If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Management estimates the fair value of the reporting unit by using the income approach or a combination of the income and market approach. The income approach is applied using a discounted cash flow analysis which relies on management’s best estimate of the reporting units’ projected cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. When using the market approach, management estimates fair value based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the fair value include discount and growth rates, rate case assumptions, valuation of Emera’s net operating loss (“NOL”), utility sector market performance and transactions, projected operating and capital cash flows and the fair value of debt. Adverse changes in assumptions described above could result in a future material impairment of the goodwill assigned to Emera’s reporting units with goodwill.

Emera reviews recorded goodwill at least annually (during the fourth quarter) for each reporting unit to which goodwill has been allocated, with interim impairment tests performed when impairment indicators are present. No impairment provisions were required for either 2018 or 2017. Refer to note 21 for further detail.

Equity Method Investments

The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the fair value of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s fair value.

Financial Assets

Equity investments, other than those accounted for under the equity method of accounting, are measured at fair value with changes in fair value recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable fair values are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments.

Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

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An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study.

As at December 31, 2018 and 2017, some of the Company’s transmission and distribution assets may have conditional ARO’s which are not recognized in the consolidated financial statements as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value in the period in which an amount can be determined.

Cost of Removal

Tampa Electric, PGS, NMGC and NSPI recognize non-ARO costs of removal (“COR”) as regulatory liabilities. The non-ARO costs of removal represent funds received from customers through depreciation rates to cover estimated future non-legally required cost of removal of property, plant and equipment upon retirement. The companies accrue for removal costs over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays.

Stock-Based Compensation

The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company accounts for its plans in accordance with the fair value based method of accounting for stock-based compensation. Stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are initially measured at fair value and re-measured at fair value at each reporting date with the change in liability recognized in income.

Employee Benefits

The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in AOCI or regulatory assets.

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2. CHANGE IN ACCOUNTING POLICY

The new USGAAP accounting policies that are applicable to, and adopted by the Company in 2018, are described as follows:

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Updates (“ASU”) No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The standard allows reclassification from accumulated other comprehensive income to retained earnings for certain tax effects resulting from the US Tax Cuts and Jobs Act that would otherwise be stranded in accumulated other comprehensive income. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted. The Company early adopted the standard in Q2 2018 and elected to not reclassify tax effects resulting from the US Tax Cuts and Jobs Act stranded in accumulated other comprehensive income to retained earnings as amounts were not material. Emera utilizes a portfolio approach to determine the timing and extent to which stranded income tax effects from items that were previously recorded in accumulated other comprehensive income are released.

Revenue from Contracts with Customers

On January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers and all the related amendments, which created a new, principle-based revenue recognition framework. The standard has been codified as Accounting Standards Codification (“ASC”) Topic 606. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled to. The guidance requires additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.

The Company adopted ASC 606 using the modified retrospective method. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting practices. The adoption of ASC 606 resulted in no adjustments to the Company’s opening retained earnings as of the adoption date. The impact of the adoption of the new standard was immaterial to the Company’s net income and is expected to be immaterial on an ongoing basis.

Recognition and Measurement of Financial Assets and Financial Liabilities

On January 1, 2018, the Company adopted ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities and all of the related amendments. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.

The standard requires investments in equity securities, except those accounted for under the equity method of accounting or those that result in consolidation, to be measured at fair value. The Company has elected to measure equity securities that do not have a readily determinable fair value at cost minus impairment (if any), plus or minus observable price changes resulting from transactions for the identical or similar investments of the same issuer. The standard eliminates the available-for-sale classification for equity investments that recognized changes in the fair value as a component of other comprehensive income, resulting in all changes in fair value being recognized in net income. The impact as a result of the remeasurement of equity investments is expected to be immaterial to the Company’s net income on an ongoing basis. A cumulative-effect adjustment of $4 million was made which increased retained earnings in the Consolidated Balance Sheet as of January 1, 2018.

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Clarifying the Definition of a Business

In January 2017, the FASB issued ASU 2017-01, Clarifying the Definition of a Business. The standard provides guidance to assist entities with evaluating when a set of transferred assets and activities is a business. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and is required to be applied prospectively. The Company adopted ASU 2017-01 effective January 1, 2018. There was no impact on the consolidated financial statements as a result of the adoption of this standard.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component is eligible for capitalization as property, plant and equipment under this guidance. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance around capitalization.

The Company adopted ASU 2017-07 effective January 1, 2018 and December 31, 2017 balances have been retrospectively restated in the Consolidated Statements of Income. The standard allows the Company to use the amounts disclosed in its pension and other postretirement benefit plan note for the prior comparative periods as the estimation basis for applying the retrospective presentation requirements. This change resulted in $27 million of costs, previously presented within “Operating, maintenance and general”, being reclassified to “Other income (expense), net” in the Consolidated Statements of Income for the year ended December 31, 2017.

3. FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all ASUs issued by the FASB. The following updates have been issued by the FASB, but have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or have an insignificant impact on the consolidated financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the previous guidance, operating leases are not recorded as assets and liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted and is required to be applied using a modified retrospective approach. The Company will not early adopt the standard.

In January 2018, the FASB issued an amendment to ASC Topic 842 that permits companies to elect to not evaluate existing land easements under the new standard if the land easements were not previously accounted for under existing lease guidance. The Company will make this election. In July 2018, the FASB issued an amendment to ASC Topic 842 that permits companies to elect not to restate their comparative periods in the period of adoption when transitioning to the standard. The Company will make this election. Additionally, the Company will elect the options that allow the Company to not reassess whether any expired or existing contracts contain leases, carry forward existing lease classification, use hindsight to determine the lease term for existing leases and not separate lease components from non-lease components for all lessee and lessor arrangements.

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Over the past several years, the Company developed and executed a project plan which included holding training sessions with key stakeholders throughout the organization, gathering detailed information on existing lease arrangements, evaluating implementation alternatives and calculating the lease asset and liability balances associated with individual contractual arrangements. The Company has implemented additional processes and controls to facilitate the identification, tracking and reporting of potential leases based on the requirements of the standard. Updates to systems are not required as a result of implementation of this standard. The adoption of this standard will affect the Company’s financial position by increasing assets and liabilities related to operating leases by approximately $70 million, with no impact to the Company’s Consolidated Statements of Income. There will be no significant changes to the Company’s accounting for lessor arrangements as a result of the adoption of the standard. The Company is in the process of assessing the disclosure requirements and continues to monitor FASB amendments to ASC Topic 842.

Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. The standard provides guidance regarding the measurement of credit losses for financial assets and certain other instruments that are not accounted for at fair value through net income, including trade and other receivables, debt securities, net investment in leases, and off-balance sheet credit exposures. The new guidance requires companies to replace the current incurred loss impairment methodology with a methodology that measures all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance expands the disclosure requirements regarding credit losses, including the credit loss methodology and credit quality indicators.

This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted for annual reporting periods, including interim periods after December 15, 2018 and will be applied using a modified retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in ASC Topic 815. This standard improves the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and simplifies the application of hedge accounting. The standard will make more financial and nonfinancial hedging strategies eligible for hedge accounting, amends the presentation and disclosure requirements for hedging activities and changes how entities assess hedge effectiveness. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018, with early adoption permitted, and is required to be applied using a modified retrospective approach. The adoption of this standard will have no impact on the Company’s consolidated financial statements.

Cloud Computing

In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. The Company is currently evaluating the transition methods and the impact of the adoption of this standard on the consolidated financial statements.

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4. SEGMENT INFORMATION

Emera manages its reportable segments separately due in part to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. Emera’s six reportable segments are Emera Florida and New Mexico, NSPI, Emera Maine, Emera Caribbean, Emera Energy and Corporate and Other (includes Emera Utility Services, ENL, Emera Brunswick Pipeline, Corporate, other strategic investments and certain holding companies). The Company is reviewing its internal reporting to the chief operating decision maker and considering changes to its reportable segments for 2019.

millions of Canadian dollars |  | Emera Florida and New Mexico |  |  | NSPI |  |  | Emera Maine |  |  | Emera Caribbean |  |  | Emera Energy |  |  | Corporate and Other |  |  | Inter- segment Eliminations |  |  | Total |
For the year ended December 31, 2018 |
Operating revenues from external customers (1) |  | $ | 3,675 |  |  | $ | 1,437 |  |  | $ | 278 |  |  | $ | 467 |  |  | $ | 600 |  |  | $ | 68 |  |  | $ | - |  |  | $ | 6,525 |
Inter-segment revenues (1) |  |  | - |  |  |  | 3 |  |  |  | - |  |  |  | - |  |  |  | 14 |  |  |  | 36 |  |  |  | (54) |  |  |  | (1) |
Total operating revenues |  |  | 3,675 |  |  |  | 1,440 |  |  |  | 278 |  |  |  | 467 |  |  |  | 614 |  |  |  | 104 |  |  |  | (54) |  |  |  | 6,524 |
AFUDC - debt and equity |  |  | 21 |  |  |  | 6 |  |  |  | 3 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 30 |
Regulated fuel and fixed cost deferral adjustments |  |  | - |  |  |  | (46) |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (46) |
Depreciation and amortization |  |  | 534 |  |  |  | 219 |  |  |  | 64 |  |  |  | 50 |  |  |  | 46 |  |  |  | 3 |  |  |  | - |  |  |  | 916 |
Interest expense (2) |  |  | 238 |  |  |  | 142 |  |  |  | 22 |  |  |  | 27 |  |  |  | 5 |  |  |  | 290 |  |  |  | - |  |  |  | 724 |
Internally allocated interest (3) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (24) |  |  |  | 24 |  |  |  | - |  |  |  | - |
Income from equity investments |  |  | - |  |  |  | - |  |  |  | 3 |  |  |  | 3 |  |  |  | 38 |  |  |  | 110 |  |  |  | - |  |  |  | 154 |
Income tax expense (recovery) |  |  | 101 |  |  |  | 8 |  |  |  | 11 |  |  |  | (2) |  |  |  | 66 |  |  |  | (115) |  |  |  | - |  |  |  | 69 |
Net income attributable to common shareholders |  |  | 428 |  |  |  | 131 |  |  |  | 44 |  |  |  | 41 |  |  |  | 165 |  |  |  | (99) |  |  |  | - |  |  |  | 710 |
Capital expenditures |  |  | 1,548 |  |  |  | 345 |  |  |  | 100 |  |  |  | 87 |  |  |  | 33 |  |  |  | 38 |  |  |  | - |  |  |  | 2,151 |
As at December 31, 2018 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets |  |  | 20,051 |  |  |  | 5,143 |  |  |  | 1,721 |  |  |  | 1,373 |  |  |  | 1,785 |  |  |  | 2,275 |  |  |  | (34) |  |  |  | 32,314 |
Investments subject to significant influence (4) |  |  | - |  |  |  | - |  |  |  | 35 |  |  |  | 42 |  |  |  | - |  |  |  | 1,239 |  |  |  | - |  |  |  | 1,316 |
Goodwill |  |  | 6,053 |  |  |  | - |  |  |  | 156 |  |  |  | 104 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 6,313 |

(1) All significant intercompany balances and intercompany transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Intercompany transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Interest expense is net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $12 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy.

(3) Segment net income is reported on a basis that includes internally allocated financing costs.

(4) Emera Energy’s segment includes an investment in Bear Swamp. At December 31, 2018 this investment is in a credit position of $172 million and is recorded in “Other long-term liabilities” on the Consolidated Balance Sheets.

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millions of Canadian dollars |  | Emera Florida and New Mexico |  |  | NSPI |  |  | Emera Maine |  |  | Emera Caribbean |  |  | Emera Energy |  |  | Corporate and Other |  |  | Inter- segment Eliminations |  |  | Total |
For the year ended December 31, 2017 |
Operating revenues from external customers (1) |  | $ | 3,623 |  |  | $ | 1,335 |  |  | $ | 297 |  |  | $ | 434 |  |  | $ | 451 |  |  | $ | 86 |  |  | $ | - |  |  | $ | 6,226 |
Inter-segment revenues (1) |  |  | - |  |  |  | 3 |  |  |  | - |  |  |  | - |  |  |  | 14 |  |  |  | 41 |  |  |  | (58) |  |  |  | - |
Total operating revenues |  |  | 3,623 |  |  |  | 1,338 |  |  |  | 297 |  |  |  | 434 |  |  |  | 465 |  |  |  | 127 |  |  |  | (58) |  |  |  | 6,226 |
AFUDC - debt and equity |  |  | 5 |  |  |  | 8 |  |  |  | 3 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 16 |
Regulated fuel and fixed cost deferral adjustments |  |  | - |  |  |  | 59 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 59 |
Depreciation and amortization |  |  | 500 |  |  |  | 207 |  |  |  | 47 |  |  |  | 51 |  |  |  | 48 |  |  |  | 3 |  |  |  | - |  |  |  | 856 |
Interest expense (2) |  |  | 248 |  |  |  | 134 |  |  |  | 20 |  |  |  | 25 |  |  |  | 2 |  |  |  | 276 |  |  |  | - |  |  |  | 705 |
Internally allocated interest (3) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (24) |  |  |  | 24 |  |  |  | - |  |  |  | - |
Income from equity investments |  |  | - |  |  |  | - |  |  |  | 1 |  |  |  | 3 |  |  |  | 24 |  |  |  | 96 |  |  |  | - |  |  |  | 124 |
Income tax expense (recovery) |  |  | 529 |  |  |  | - |  |  |  | 27 |  |  |  | - |  |  |  | 18 |  |  |  | (54) |  |  |  | - |  |  |  | 520 |
Net income attributable to common shareholders |  |  | 99 |  |  |  | 129 |  |  |  | 46 |  |  |  | 31 |  |  |  | 93 |  |  |  | (132) |  |  |  | - |  |  |  | 266 |
Capital expenditures |  |  | 910 |  |  |  | 385 |  |  |  | 82 |  |  |  | 72 |  |  |  | 47 |  |  |  | 26 |  |  |  | - |  |  |  | 1,522 |
As at December 31, 2017 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets |  |  | 17,216 |  |  |  | 4,979 |  |  |  | 1,540 |  |  |  | 1,251 |  |  |  | 1,575 |  |  |  | 2,331 |  |  |  | (86) |  |  |  | 28,806 |
Investments subject to significant influence (4) |  |  | - |  |  |  | - |  |  |  | 13 |  |  |  | 39 |  |  |  | - |  |  |  | 1,163 |  |  |  | - |  |  |  | 1,215 |
Goodwill |  |  | 5,566 |  |  |  | - |  |  |  | 143 |  |  |  | 96 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 5,805 |

(1) All significant intercompany balances and intercompany transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes the elimination of these transactions would understate property, plant and equipment, OM&G expenses, or regulated fuel for generation and purchased power. Intercompany transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Interest expense is net of interest revenue. Corporate and Other Interest expense has also been reduced by amortization of $24 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy.

(3) Segment net income is reported on a basis that includes internally allocated financing costs.

(4) Emera Energy’s segment includes an investment in Bear Swamp. At December 31, 2017 this investment is in a credit position of $188 million and is recorded in “Other long-term liabilities” on the Consolidated Balance Sheets.

Geographical Information

Revenues (1):

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2018 |  |  | 2017 |
Canada |  | $ | 1,520 |  |  | $ | 1,464 |
United States |  |  | 4,537 |  |  |  | 4,328 |
Barbados |  |  | 319 |  |  |  | 280 |
The Bahamas |  |  | 121 |  |  |  | 119 |
Dominica |  |  | 27 |  |  |  | 35 |
|  | $ | 6,524 |  |  | $ | 6,226 |
(1) Revenues are based on country of origin of the product or service sold. |  |  |  |  |  |  |  |
Property Plant and Equipment: |
As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |
Canada |  | $ | 4,128 |  |  | $ | 3,995 |
United States |  |  | 13,739 |  |  |  | 12,257 |
Barbados |  |  | 446 |  |  |  | 408 |
The Bahamas |  |  | 315 |  |  |  | 276 |
Dominica |  |  | 84 |  |  |  | 59 |
|  | $ | 18,712 |  |  | $ | 16,995 |

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5. REVENUE

The following disaggregates the Company’s revenue by major source:

millions of Canadian dollars |  | Emera Florida and New Mexico |  |  | NSPI |  |  | Emera Maine |  |  | Emera Caribbean |  |  | Emera Energy |  |  | Corporate and Other |  |  | Inter- Segment Eliminations |  |  | Total |
For the year ended December 31, 2018 |
Regulated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric Revenue |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 1,384 |  |  | $ | 731 |  |  | $ | 107 |  |  | $ | 154 |  |  | $ | - |  |  | $ | - |  |  | $ | - |  |  | $ | 2,376 |
Commercial |  |  | 755 |  |  |  | 405 |  |  |  | 80 |  |  |  | 270 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 1,510 |
Industrial |  |  | 209 |  |  |  | 233 |  |  |  | 16 |  |  |  | 30 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 488 |
Other electric and regulatory deferrals |  |  | 312 |  |  |  | 43 |  |  |  | 9 |  |  |  | 7 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 371 |
Other (1) |  |  | 10 |  |  |  | 28 |  |  |  | 66 |  |  |  | 6 |  |  |  | - |  |  |  | - |  |  |  | (3) |  |  |  | 107 |
Regulated electric revenue |  |  | 2,670 |  |  |  | 1,440 |  |  |  | 278 |  |  |  | 467 |  |  |  | - |  |  |  | - |  |  |  | (3) |  |  |  | 4,852 |
Gas Revenue |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  | 492 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 492 |
Commercial |  |  | 291 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 291 |
Industrial |  |  | 49 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 49 |
Finance income (2)(3) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 57 |  |  |  | - |  |  |  | 57 |
Other |  |  | 155 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 155 |
Regulated gas revenue |  |  | 987 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 57 |  |  |  | - |  |  |  | 1,044 |
Non-Regulated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Marketing and trading margin (4) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 115 |  |  |  | - |  |  |  | - |  |  |  | 115 |
Energy sales (4) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 309 |  |  |  | - |  |  |  | (16) |  |  |  | 293 |
Capacity |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 136 |  |  |  | - |  |  |  | - |  |  |  | 136 |
Other |  |  | 18 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 47 |  |  |  | (35) |  |  |  | 30 |
Mark-to-market (3) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 54 |  |  |  | - |  |  |  | - |  |  |  | 54 |
Non-regulated revenue |  |  | 18 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 614 |  |  |  | 47 |  |  |  | (51) |  |  |  | 628 |
Total operating revenues |  | $ | 3,675 |  |  | $ | 1,440 |  |  | $ | 278 |  |  | $ | 467 |  |  | $ | 614 |  |  | $ | 104 |  |  | $ | (54) |  |  | $ | 6,524 |

(1) Other includes an immaterial amount of rental revenues, which do not represent revenue from contracts with customers.

(2) Revenue related to Brunswick Pipeline’s service agreement with Repsol Energy Canada.

(3) Revenue which does not represent revenues from contracts with customers.

(4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts with customers.

Remaining Performance Obligations

Remaining performance obligations primarily represent gas transportation contracts, lighting contracts and long-term steam supply arrangements with fixed contract terms. As of December 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was $370 million. As allowed by the practical expedient in ASC 606, this amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2033.

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6. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Investments subject to significant influence consisted of the following:

millions of Canadian dollars |  | Carrying Value As at December 31 |  |  |  |  |  | Equity Income For the year ended December 31 |  |  | Percentage of Ownership |
|  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |  |  | 2018 |
NSPML |  | $ | 545 |  |  | $ | 510 |  |  | $ | 45 |  |  | $ | 36 |  |  |  | 100.0 |
LIL (1) |  |  | 534 |  |  |  | 492 |  |  |  | 42 |  |  |  | 37 |  |  |  | 49.5 |
M&NP (2) |  |  | 155 |  |  |  | 156 |  |  |  | 22 |  |  |  | 23 |  |  |  | 12.9 |
Lucelec (2) |  |  | 42 |  |  |  | 39 |  |  |  | 3 |  |  |  | 3 |  |  |  | 19.1 |
Bear Swamp (3) |  |  | - |  |  |  | - |  |  |  | 38 |  |  |  | 23 |  |  |  | 50.0 |
Other Investments |  |  | 40 |  |  |  | 18 |  |  |  | 4 |  |  |  | 2 |  |  |  |  |
|  | $ | 1,316 |  |  | $ | 1,215 |  |  | $ | 154 |  |  | $ | 124 |  |  |  |  |

(1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. Emera’s percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments.

(2) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method.

(3) The investment balance in Bear Swamp is in a credit position, primarily a result of a $179 million distribution received in Q4 2015. Bear Swamp’s credit investment balance of $172 million (2017 - $188 million) is recorded in “Other long-term liabilities” on the Consolidated Balance Sheets.

Equity investments include a $12 million difference between the cost and the underlying fair value of the investees’ assets as at the date of acquisition. The excess is attributable to goodwill.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 31). NSPML’s consolidated summarized balance sheets are illustrated as follows:

As at |  | December 31 |
millions of Canadian dollars |  | 2018 |  |  | 2017 |
Balance Sheets |  |  |  |  |  |  |  |
Current assets |  | $ | 86 |  |  | $ | 225 |
Property, plant and equipment |  |  | 1,690 |  |  |  | 1,720 |
Non-current assets |  |  | 140 |  |  |  | 74 |
Total assets |  | $ | 1,916 |  |  | $ | 2,019 |
Current liabilities |  | $ | 21 |  |  | $ | 180 |
Long-term debt |  |  | 1,288 |  |  |  | 1,287 |
Non-current liabilities |  |  | 62 |  |  |  | 42 |
Equity |  |  | 545 |  |  |  | 510 |
Total liabilities and equity |  | $ | 1,916 |  |  | $ | 2,019 |

27

7. INCOME TAXES

The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and Nova Scotia and New Brunswick provincial statutory income tax rate for the following reasons:

millions of Canadian dollars |  | 2018 |  |  | 2017 |
Income before provision for income taxes |  | $ | 816 |  |  | $ | 819 |
Statutory income tax rate |  |  | 31% |  |  |  | 31% |
Income taxes, at statutory income tax rate |  |  | 253 |  |  |  | 254 |
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities |  |  | (59) |  |  |  | (54) |
Foreign tax rate variance |  |  | (55) |  |  |  | 36 |
Amortization of deferred income tax regulatory liabilities |  |  | (37) |  |  |  | - |
Florida state tax apportionment adjustment |  |  | (23) |  |  |  | - |
Tax effect of equity earnings |  |  | (15) |  |  |  | (12) |
Financing deductions |  |  | (4) |  |  |  | (17) |
Revaluation of US non-regulated deferred income taxes due to tax reform |  |  | - |  |  |  | 317 |
Other |  |  | 9 |  |  |  | (4) |
Income tax expense (recovery) |  | $ | 69 |  |  | $ | 520 |
Effective income tax rate |  |  | 8% |  |  |  | 63% |

On December 22, 2017, the US Tax Cuts and Jobs Act of 2017 (“the Act”) was signed into law enacting a broad range of legislative changes including reduction of the US federal corporate income tax rate from 35 per cent to 21 per cent effective January 1, 2018, limitations on the deductibility of interest and 100 per cent expensing of qualified property. The Act provides an exemption to regulated electric and gas utilities from the limitations on the deductibility of interest and the 100 per cent expensing of qualified property.

At December 31, 2017, the Company was required to revalue its US deferred income tax assets and liabilities based on the new tax rate at the date of enactment. The Company recognized a $317 million income tax expense as a result of the revaluation of its US non-regulated net deferred income tax assets. The Company also reduced its US regulated net deferred income tax liabilities by $1.1 billion and recorded an equivalent regulatory liability since the benefit of lower US taxes is expected to be returned to customers over time as required by the Act or by order of the applicable regulator. The December 31, 2017 balances of deferred income tax assets and liabilities that were revalued were $1.3 billion and $1.8 billion, respectively.

No further adjustments were recognized in 2018 and the Company has completed its accounting for the revaluation of its US deferred income tax assets and liabilities resulting from the effects of the Act. The measurement period allowed by SEC Staff Accounting Bulletin 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act is now closed.

In Q4 2018, the Company reclassified $149 million of AMT credit carryforwards from deferred income tax assets to receivables and other current assets as it expects to receive the refund in 2019.

On November 26, 2018, the Internal Revenue Service (“IRS”) issued proposed regulations on the interest deductibility limitation rules legislated under the Act. The Company believes its US based financing interest will be deductible under the Act.

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The following reflects the composition of taxes on income from continuing operations presented in the Consolidated Statements of Income for the years ended December 31:

millions of Canadian dollars |  | 2018 |  |  | 2017 |
Current income taxes |  |  |  |  |  |  |  |
Canada |  | $ | 3 |  |  | $ | 24 |
United States |  |  | (121) |  |  |  | 24 |
Other |  |  | 2 |  |  |  | 3 |
Deferred income taxes |  |  |  |  |  |  |  |
Canada |  |  | 11 |  |  |  | 3 |
United States |  |  | 211 |  |  |  | 384 |
Other |  |  | (3) |  |  |  | (1) |
Operating loss carryforwards |  |  |  |  |  |  |  |
Canada |  |  | (33) |  |  |  | (40) |
United States |  |  | - |  |  |  | (194) |
Other |  |  | (1) |  |  |  | - |
Revaluation of US non-regulated deferred income taxes |  |  |  |  |  |  |  |
United States |  |  | - |  |  |  | 317 |
Income tax expense (recovery) |  | $ | 69 |  |  | $ | 520 |
The following reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: |

millions of Canadian dollars |  | 2018 |  |  | 2017 |
Canada |  | $ | 127 |  |  | $ | 88 |
United States |  |  | 646 |  |  |  | 693 |
Other |  |  | 43 |  |  |  | 38 |
Income before provision for income taxes |  | $ | 816 |  |  | $ | 819 |

The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following:

millions of Canadian dollars |  | 2018 |  |  | 2017 |
Deferred income tax assets: |  |  |  |  |  |  |  |
Tax loss carryforwards |  | $ | 917 |  |  | $ | 853 |
Tax credit carryforwards |  |  | 269 |  |  |  | 314 |
Regulatory liabilities - cost of removal |  |  | 206 |  |  |  | 208 |
Pension and post-retirement liabilities |  |  | 126 |  |  |  | 112 |
Derivative instruments |  |  | 90 |  |  |  | 107 |
Other |  |  | 441 |  |  |  | 394 |
Total deferred income tax assets before valuation allowance |  |  | 2,049 |  |  |  | 1,988 |
Valuation allowance |  |  | (163) |  |  |  | (105) |
Total deferred income tax assets after valuation allowance |  | $ | 1,886 |  |  | $ | 1,883 |
Deferred income tax (liabilities): |  |  |  |  |  |  |  |
Property, plant and equipment |  | $ | (2,591) |  |  | $ | (2,321) |
Derivative instruments |  |  | (124) |  |  |  | (155) |
Other |  |  | (316) |  |  |  | (292) |
Total deferred income tax liabilities |  | $ | (3,031) |  |  | $ | (2,768) |
Consolidated Balance Sheets presentation: |  |  |  |  |  |  |  |
Long-term deferred income tax assets |  | $ | 175 |  |  | $ | 138 |
Long-term deferred income tax liabilities |  |  | (1,320) |  |  |  | (1,023) |
Net deferred income tax liabilities |  | $ | (1,145) |  |  | $ | (885) |

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Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that Emera is more likely than not to realize all recorded deferred income tax assets, except for certain loss carryforwards and unrealized capital losses on investments. A valuation allowance of $163 million has been recorded as at December 31, 2018 (2017 - $105 million) related to the loss carryforwards and investments.

Emera’s net operating loss (“NOL”), capital loss and tax credit carryforwards and their expiration periods as at December 31, 2018 consisted of the following:

millions of Canadian dollars |  | Gross Tax Carryforwards |  |  | Unrecognized Amounts |  |  | Net Tax Carryforwards |  |  | Expiration Period |
Canada |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NOL |  | $ | 817 |  |  | $ | (405) |  |  | $ | 412 |  |  |  | 2027-2038 |
Capital loss |  |  | 86 |  |  |  | (77) |  |  |  | 9 |  |  |  | Indefinite |
United States |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Federal NOL |  | $ | 2,848 |  |  | $ | - |  |  | $ | 2,848 |  |  |  | 2024-2037 |
State NOL |  |  | 1,314 |  |  |  | (47) |  |  |  | 1,267 |  |  |  | 2024-2038 |
Capital loss |  |  | 6 |  |  |  | (6) |  |  |  | - |  |  |  | 2019 |
Tax credit |  |  | 268 |  |  |  | - |  |  |  | 268 |  |  |  | 2019-Indefinite |
Other |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NOL |  | $ | 34 |  |  | $ | (34) |  |  | $ | - |  |  |  | 2019-2025 |

The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows:

millions of Canadian dollars |  | 2018 |  |  | 2017 |
Balance, January 1 |  | $ | 19 |  |  | $ | 18 |
Increases due to tax positions related to a prior year |  |  | 8 |  |  |  | - |
Decreases due to tax positions related to a prior year |  |  | (1) |  |  |  | - |
Increases due to tax positions related to current year |  |  | - |  |  |  | 1 |
Balance, December 31 |  | $ | 26 |  |  | $ | 19 |

The total amount of unrecognized tax benefits as at December 31, 2018 was $26 million (2017 - $19 million), which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $4 million (2017 - $1 million) with $3 million of interest expense recognized in the Consolidated Statement of Income (2017 - nil). No penalties have been accrued. The balance of unrecognized tax benefits could change in the next twelve months as a result of resolving Canada Revenue Agency (“CRA”) and IRS audits. A reasonable estimate of any change cannot be made at this time.

The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, US and non-US income and withholding taxes for which deferred taxes might otherwise be required have not been provided for on a cumulative amount of temporary differences related to investments in foreign subsidiaries of approximately $1.4 billion as at December 31, 2018 (2017 - $822 million). It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred.

Emera files a Canadian federal income tax return, which includes its Nova Scotia and New Brunswick provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, St. Lucia and Dominica income tax returns. As at December 31, 2018, the Company’s tax years still open to examination by taxing authorities include 2005 and subsequent years.

NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for NSPI’s 2006 through 2010 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $62 million, including interest. NSPI has prepaid $23 million of the amount in dispute, as required by CRA.

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Should NSPI be successful in defending its position, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the excess, if any, owing to CRA. The related tax deductions will be available in subsequent years. Should NSPI receive similar notices of reassessment for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.

NSPI and its advisors believe NSPI has reported its tax position appropriately and NSPI is disputing the reassessments through the CRA Appeal process. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Appeal process is not determinable at this time.

8. COMMON STOCK

Authorized: Unlimited number of non-par value common shares.

|  | 2018 |  |  | 2017 |
Issued and outstanding: |  | millions of shares |  |  | millions of Canadian dollars |  |  | millions of shares |  |  | millions of Canadian dollars |
Balance, December 31, 2017 |  |  | 228.77 |  |  | $ | 5,601 |  |  |  | 210.02 |  |  | $ | 4,738 |
Conversion of Convertible Debentures |  |  | 0.01 |  |  |  | - |  |  |  | 0.15 |  |  |  | 6 |
Issuance of common stock (1) |  |  | 0.45 |  |  |  | 22 |  |  |  | 14.61 |  |  |  | 680 |
Issued under Purchase Plans at market rate |  |  | 4.87 |  |  |  | 200 |  |  |  | 3.89 |  |  |  | 182 |
Discount on shares purchased under Dividend Reinvestment Plan |  |  | - |  |  |  | (9) |  |  |  | - |  |  |  | (9) |
Options exercised under senior management share option plan |  |  | 0.02 |  |  |  | 1 |  |  |  | 0.10 |  |  |  | 3 |
Employee Share Purchase Plan |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Balance, December 31, 2018 |  |  | 234.12 |  |  | $ | 5,816 |  |  |  | 228.77 |  |  | $ | 5,601 |

(1) In Q1 2018, Emera issued 0.45 million common shares to facilitate the creation and issuance of 1.8 million depository receipts in connection with the ICDU share acquisition. The depository receipts are listed on the Bahamas International Securities Exchange.

As at December 31, 2018, the following common shares were reserved for issuance: 6.5 million (2017 – 6.5 million) under the senior management stock option plan, 1.0 million (2017 – 1.3 million) under the employee common share purchase plan and 12.6 million (2017 – 4.2 million) under the dividend reinvestment plan (“DRIP”).

The issuance of common shares under the common share compensation arrangements does not allow the plans to exceed 10 per cent of Emera’s outstanding common shares. As at December 31, 2018, Emera is in compliance with this requirement.

9. EARNINGS PER SHARE

Basic earnings per share (“EPS”) is determined by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the senior management stock option plan, convertible debentures and shares issued under the dividend reinvestment plan.

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The following table reconciles the computation of basic and diluted earnings per share:

For the |  | Year ended December 31 |
millions of Canadian dollars (except per share amounts) |  | 2018 |  |  | 2017 |
Numerator |  |  |  |  |  |  |  |
Net income attributable to common shareholders |  | $ | 709.6 |  |  | $ | 266.1 |
Diluted numerator |  |  | 709.6 |  |  |  | 266.1 |
Denominator |  |  |  |  |  |  |  |
Weighted average shares of common stock outstanding |  |  | 231.7 |  |  |  | 212.3 |
Weighted average deferred share units outstanding |  |  | 1.3 |  |  |  | 1.1 |
Weighted average shares of common stock outstanding – basic |  |  | 233.0 |  |  |  | 213.4 |
Stock-based compensation |  |  | 0.4 |  |  |  | 0.6 |
Convertible Debentures |  |  | 0.1 |  |  |  | 0.1 |
Weighted average shares of common stock outstanding – diluted |  |  | 233.5 |  |  |  | 214.1 |
Earnings per common share |  |  |  |  |  |  |  |
Basic |  | $ | 3.05 |  |  | $ | 1.25 |
Diluted |  | $ | 3.04 |  |  | $ | 1.24 |

10. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income are as follows:

millions of Canadian dollars |  | Unrealized (loss) gain on translation of self-sustaining foreign operations |  |  | Net change in net investment hedges |  |  | (Losses) gains on derivatives recognized as cash flow hedges |  |  | Net change on available-for- sale investments |  |  | Net change in unrecognized pension and post-retirement benefit costs |  |  | Total AOCI |
Balance, January 1, 2018 |  | $ | 30 |  |  | $ | 48 |  |  | $ | (3) |  |  | $ | 3 |  |  | $ | (243) |  |  | $ | (165) |
Other comprehensive income (loss) before reclassifications |  |  | 624 |  |  |  | (122) |  |  |  | 2 |  |  |  | - |  |  |  | - |  |  |  | 504 |
Amounts reclassified from accumulated other comprehensive income loss |  |  | - |  |  |  | - |  |  |  | (6) |  |  |  | (4) |  |  |  | 9 |  |  |  | (1) |
Net current period other comprehensive income (loss) |  |  | 624 |  |  |  | (122) |  |  |  | (4) |  |  |  | (4) |  |  |  | 9 |  |  |  | 503 |
Balance, December 31, 2018 |  | $ | 654 |  |  | $ | (74) |  |  | $ | (7) |  |  | $ | (1) |  |  | $ | (234) |  |  | $ | 338 |
For the year ended December 31, 2017 |
Balance, January 1, 2017 (1) |  | $ | 489 |  |  | $ | (49) |  |  | $ | (21) |  |  | $ | (1) |  |  | $ | (283) |  |  | $ | 135 |
Other comprehensive income (loss) before reclassifications |  |  | (459) |  |  |  | 97 |  |  |  | 10 |  |  |  | 5 |  |  |  | - |  |  |  | (347) |
Amounts reclassified from accumulated other comprehensive income loss (gain) (2) |  |  | - |  |  |  | - |  |  |  | 8 |  |  |  | (1) |  |  |  | 40 |  |  |  | 47 |
Net current period other comprehensive income (loss) |  |  | (459) |  |  |  | 97 |  |  |  | 18 |  |  |  | 4 |  |  |  | 40 |  |  |  | (300) |
Balance, December 31, 2017 |  | $ | 30 |  |  | $ | 48 |  |  | $ | (3) |  |  | $ | 3 |  |  | $ | (243) |  |  | $ | (165) |

(1) The January 1, 2017 balance of AOCI and Regulatory Assets includes a prior period reclassification of $44 million in unrecognized pension and post-retirement benefit costs and $18 million in deferred taxes ($26 million, net of tax) to be consistent with current year presentation.

(2) Certain net changes in unrecognized pension and post-retirement benefit costs for Emera Maine of $4 million were previously presented as a change in AOCI and are now presented as a change in Regulatory Assets for the year ended December 31, 2017 to be consistent with current year presentation.

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The reclassifications out of accumulated other comprehensive income (loss) are as follows:

For the |  |  |  | Year ended December 31 |
millions of Canadian dollars |  |  |  | 2018 |  |  | 2017 |
Affected line item in the Consolidated Financial Statements |  |  |  |  |  |  |  |
Losses (gain) on derivatives recognized as cash flow hedges |  |  |  |  |  |  |  |
Power and gas swaps |  | Non-regulated fuel for generation and purchased power |  | $ | (1) |  |  | $ | (3) |
Foreign exchange forwards |  | Operating revenue - regulated |  |  | (5) |  |  |  | 10 |
Total before tax |  |  |  |  | (6) |  |  |  | 7 |
|  | Income tax recovery (expense) |  |  | - |  |  |  | 1 |
Total net of tax |  |  |  | $ | (6) |  |  | $ | 8 |
Net change in available-for-sale investments |  |  |  |  |  |  |  |
|  | Other income (expenses), net |  | $ | - |  |  | $ | (1) |
|  | Retained earnings (1) |  |  | (4) |  |  |  | - |
Total net of tax |  |  |  | $ | (4) |  |  | $ | (1) |
Net change in unrecognized pension and post-retirement benefit costs |  |  |  |  |  |  |  |
Actuarial losses (gains) |  | Operating, maintenance and general (“OM&G”) |  | $ | 25 |  |  | $ | 33 |
Past service costs (gains) |  | OM&G |  |  | (1) |  |  |  | (8) |
Amounts reclassified into obligations |  | Pension and post-retirement benefits |  |  | (17) |  |  |  | 11 |
Total before tax |  |  |  |  | 7 |  |  |  | 36 |
|  | Income tax recovery (expense) |  |  | 2 |  |  |  | 4 |
Total net of tax |  |  |  | $ | 9 |  |  | $ | 40 |
Total reclassifications out of AOCI, net of tax, for the period |  | $ | (1) |  |  | $ | 47 |

(1) Related to the adoption of ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. Refer to note 2 for additional detail.

11. INVENTORY

Inventory consisted of the following:

As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |
Fuel |  | $ | 213 |  |  | $ | 180 |
Materials |  |  | 241 |  |  |  | 216 |
Emission credits (1) |  |  | 20 |  |  |  | 22 |
|  | $ | 474 |  |  | $ | 418 |

(1) The NEGG facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative for carbon dioxide emissions. The emission credits inventory balance represents the credits purchased to offset the other current liabilities and other long-term liabilities associated with these programs.

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12. DERIVATIVE INSTRUMENTS

Derivative assets and liabilities relating to the foregoing categories consisted of the following:

|  | Derivative Assets |  |  | Derivative Liabilities |
As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |  |  | December 31 2018 |  |  | December 31 2017 |
Cash flow hedges |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps |  | $ | - |  |  | $ | 5 |  |  | $ | - |  |  | $ | 2 |
Foreign exchange forwards |  |  | - |  |  |  | 2 |  |  |  | 5 |  |  |  | 5 |
|  |  | - |  |  |  | 7 |  |  |  | 5 |  |  |  | 7 |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Coal purchases |  |  | 71 |  |  |  | 137 |  |  |  | 1 |  |  |  | 10 |
Power purchases |  |  | 2 |  |  |  | 5 |  |  |  | 1 |  |  |  | 3 |
Natural gas purchases and sales |  |  | 2 |  |  |  | 6 |  |  |  | 4 |  |  |  | 7 |
Heavy fuel oil purchases |  |  | 1 |  |  |  | 15 |  |  |  | 1 |  |  |  | 4 |
Foreign exchange forwards |  |  | 29 |  |  |  | 32 |  |  |  | - |  |  |  | 4 |
|  |  | 105 |  |  |  | 195 |  |  |  | 7 |  |  |  | 28 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | 62 |  |  |  | 125 |  |  |  | 76 |  |  |  | 162 |
Natural gas swaps, futures, forwards, physical contracts |  |  | 125 |  |  |  | 105 |  |  |  | 403 |  |  |  | 294 |
|  |  | 187 |  |  |  | 230 |  |  |  | 479 |  |  |  | 456 |
Other derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate swap |  |  | 1 |  |  |  | 2 |  |  |  | - |  |  |  | - |
|  |  | 1 |  |  |  | 2 |  |  |  | - |  |  |  | - |
Total gross current derivatives |  |  | 293 |  |  |  | 434 |  |  |  | 491 |  |  |  | 491 |
Impact of master netting agreements with intent to settle net or simultaneously |  |  | (126) |  |  |  | (181) |  |  |  | (126) |  |  |  | (181) |
|  |  | 167 |  |  |  | 253 |  |  |  | 365 |  |  |  | 310 |
Current |  |  | 148 |  |  |  | 141 |  |  |  | 260 |  |  |  | 227 |
Long-term |  |  | 19 |  |  |  | 112 |  |  |  | 105 |  |  |  | 83 |
Total derivatives |  | $ | 167 |  |  | $ | 253 |  |  | $ | 365 |  |  | $ | 310 |

Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table:

|  | Derivative Assets |  |  | Derivative Liabilities |
As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |  |  | December 31 2018 |  |  | December 31 2017 |
Regulatory deferral |  | $ | 1 |  |  | $ | 14 |  |  | $ | 1 |  |  | $ | 14 |
HFT derivatives |  |  | 125 |  |  |  | 167 |  |  |  | 125 |  |  |  | 167 |
Total impact of master netting agreements with intent to settle net or simultaneously |  | $ | 126 |  |  | $ | 181 |  |  | $ | 126 |  |  | $ | 181 |

Cash Flow Hedges

The Company enters into various derivatives designated as cash flow hedges. Emera enters into power swaps to limit Bear Swamp’s exposure to purchased power prices. The Company also enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.

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The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:

For the |  | Year ended December 31 |
millions of Canadian dollars |  |  |  |  |  |  |  | 2018 |  |  |  |  |  |  |  |  | 2017 |
|  | Power swaps |  |  | Interest rate swaps |  |  | Foreign exchange forwards |  |  | Power swaps |  |  | Interest rate swaps |  |  | Foreign exchange forwards |
Realized gain (loss) in non-regulated fuel for generation and purchased power |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | 3 |  |  |  | - |  |  |  | - |
Realized gain (loss) in operating revenue – regulated |  |  | - |  |  |  | - |  |  |  | 5 |  |  |  | - |  |  |  | - |  |  |  | (10) |
Total gains (losses) in Net income |  | $ | 1 |  |  | $ | - |  |  | $ | 5 |  |  | $ | 3 |  |  | $ | - |  |  | $ | (10) |
As at |  | December 31 |
millions of Canadian dollars |  |  |  |  |  |  |  | 2018 |  |  |  |  |  |  |  |  | 2017 |
|  | Power swaps |  |  | Interest rate swaps |  |  | Foreign exchange forwards |  |  | Power swaps |  |  | Interest rate swaps |  |  | Foreign exchange forwards |
Total unrealized gain (loss) in AOCI – effective portion, net of tax |  | $ | (1) |  |  | $ | - |  |  | $ | (6) |  |  | $ | - |  |  | $ | - |  |  | $ | (3) |

The Company expects $4 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

As at December 31, 2018, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:

millions |  | 2019 |  |  | 2020 |  |  | 2021 |
Foreign exchange forwards (USD) sales |  | $ | 30 |  |  | $ | 30 |  |  | $ | - |

Regulatory Deferral

The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:

For the |  | Year ended December 31 |
millions of Canadian dollars |  |  |  |  |  |  |  | 2018 |  |  |  |  |  |  |  |  | 2017 |
|  | Commodity swaps and forwards |  |  | Physical natural gas purchases and sales |  |  | Foreign exchange forwards |  |  | Commodity swaps and forwards |  |  | Physical natural gas purchases and sales |  |  | Foreign exchange forwards |
Unrealized gain (loss) in regulatory assets |  | $ | (34) |  |  | $ | - |  |  | $ | 4 |  |  | $ | (33) |  |  | $ | (1) |  |  | $ | (4) |
Unrealized gain (loss) in regulatory liabilities |  |  | 29 |  |  |  | - |  |  |  | 24 |  |  |  | 83 |  |  |  | 1 |  |  |  | (30) |
Realized (gain) loss in regulatory liabilities |  |  | (8) |  |  |  | - |  |  |  | - |  |  |  | (2) |  |  |  | - |  |  |  | - |
Realized (gain) loss in inventory (1) |  |  | (55) |  |  |  | - |  |  |  | (18) |  |  |  | (17) |  |  |  | - |  |  |  | (30) |
Realized (gain) loss in regulated fuel for generation and purchased power (2) |  |  | (2) |  |  |  | - |  |  |  | (9) |  |  |  | (3) |  |  |  | - |  |  |  | (14) |
Total change derivative instruments |  | $ | (70) |  |  | $ | - |  |  | $ | 1 |  |  | $ | 28 |  |  | $ | - |  |  | $ | (78) |

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable.

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Commodity Swaps and Forwards

As at December 31, 2018, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:

|  | 2019 |  |  | 2020-2023 |
millions |  | Purchases |  |  | Purchases |
Coal (metric tonnes) |  |  | 1 |  |  |  | 1 |
Natural Gas (Mmbtu) |  |  | 16 |  |  |  | - |
Heavy fuel oil (bbls) |  |  | - |  |  |  | 1 |

Foreign Exchange Swaps and Forwards

As at December 31, 2018, the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are expected to settle as outlined below:

|  | 2019 |  |  | 2020 |
Foreign exchange contracts (millions of US dollars) |  | $ | 121 |  |  | $ | 111 |
Weighted average rate |  |  | 1.1621 |  |  |  | 1.3027 |
% of USD requirements |  |  | 66% |  |  |  | 48% |

The Company reassesses foreign exchange forecasted periodically and will enter into additional hedges or unwind existing hedges, as required.

Held-for-Trading Derivatives

In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures, to economically hedge those physical contracts. These derivatives are all considered HFT.

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2018 |  |  | 2017 |
Power swaps and physical contracts in non-regulated operating revenues |  | $ | (12) |  |  | $ | 7 |
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues |  |  | 205 |  |  |  | 401 |
Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power |  |  | - |  |  |  | 10 |
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power |  |  | 2 |  |  |  | 2 |
|  | $ | 195 |  |  | $ | 420 |

As at December 31, 2018, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

millions |  | 2019 |  |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |
Natural gas purchases (Mmbtu) |  |  | 308 |  |  |  | 108 |  |  |  | 71 |  |  |  | 50 |  |  |  | 41 |
Natural gas sales (Mmbtu) |  |  | 247 |  |  |  | 42 |  |  |  | 9 |  |  |  | 2 |  |  |  | - |
Power purchases (MWh) |  |  | 6 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Power sales (MWh) |  |  | 5 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |

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Other Derivatives

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2018 |  |  | 2017 |
|  | Interest rate |  |  | Interest rate |
|  | swaps |  |  | swaps |
Unrealized gain (loss) in interest expense, net |  |  | (1) |  |  |  | 2 |
Total gains (losses) in net income |  | $ | (1) |  |  | $ | 2 |

As at December 31, 2018, the Company had interest rate swaps in place for the $250 million non-revolving term credit facility in Brunswick Pipeline for interest payments through Q1 2019.

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts.

The Company assesses the potential for credit losses on a regular basis, and where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.

As at December 31, 2018, the maximum exposure the Company has to credit risk is $1,035 million (2017 - $1,148 million), which includes accounts receivable net of collateral/deposits and assets related to derivatives.

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The total cash deposits/collateral on hand as at December 31, 2018 was $346 million (2017 - $247 million), which mitigates the Company’s maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

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As at December 31, 2018, the Company had $118 million (2017 - $90 million) in financial assets, considered to be past due, which have been outstanding for an average 68 days. The fair value of these financial assets is $107 million (2017 - $78 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric and gas revenue.

Concentration Risk

The Company’s concentrations of risk consisted of the following:

As at |  | December 31, 2018 |  |  | December 31, 2017 |
|  | millions of Canadian dollars |  |  | % of total exposure |  |  | millions of Canadian dollars |  |  | % of total exposure |
Receivables, net |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulated utilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 384 |  |  |  | 28% |  |  | $ | 326 |  |  |  | 23% |
Commercial |  |  | 182 |  |  |  | 13% |  |  |  | 161 |  |  |  | 11% |
Industrial |  |  | 57 |  |  |  | 4% |  |  |  | 46 |  |  |  | 3% |
Other |  |  | 84 |  |  |  | 6% |  |  |  | 96 |  |  |  | 7% |
|  |  | 707 |  |  |  | 51% |  |  |  | 629 |  |  |  | 44% |
Trading group |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Credit rating of A- or above |  |  | 49 |  |  |  | 4% |  |  |  | 55 |  |  |  | 4% |
Credit rating of BBB- to BBB+ |  |  | 70 |  |  |  | 5% |  |  |  | 61 |  |  |  | 4% |
Credit rating of CCC- to CCC+ |  |  | 8 |  |  |  | 0% |  |  |  | - |  |  |  | 0% |
Not rated |  |  | 108 |  |  |  | 8% |  |  |  | 96 |  |  |  | 7% |
|  |  | 235 |  |  |  | 17% |  |  |  | 212 |  |  |  | 15% |
Other accounts receivable |  |  | 273 |  |  |  | 20% |  |  |  | 300 |  |  |  | 22% |
|  |  | 1,215 |  |  |  | 88% |  |  |  | 1,141 |  |  |  | 81% |
Derivative Instruments (current and long-term) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Credit rating of A- or above |  |  | 130 |  |  |  | 9% |  |  |  | 207 |  |  |  | 15% |
Credit rating of BBB- to BBB+ |  |  | 9 |  |  |  | 1% |  |  |  | 10 |  |  |  | 1% |
Not rated |  |  | 28 |  |  |  | 2% |  |  |  | 36 |  |  |  | 3% |
|  |  | 167 |  |  |  | 12% |  |  |  | 253 |  |  |  | 19% |
|  | $ | 1,382 |  |  |  | 100% |  |  | $ | 1,394 |  |  |  | 100% |

Cash Collateral

The Company’s cash collateral positions consisted of the following:

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  | 2018 |  |  | 2017 |
Cash collateral provided to others |  |  | $ 103 |  |  |  | $ 119 |
Cash collateral received from others |  |  | 77 |  |  |  | 99 |

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at December 31, 2018, the total fair value of these derivatives, in a liability position, was $365 million (December 31, 2017 – $310 million). If the credit ratings of the Company were reduced below investment grade the full value of the net liability position could be required to be posted as collateral for these derivatives.

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13. FAIR VALUE MEASUREMENTS

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (refer to note 1) and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:

Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:

● |  | While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

● |  | The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

● |  | The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

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The following tables set out the classification of the methodology used by the Company to fair value its derivatives:

As at |  | December 31, 2018 |
millions of Canadian dollars |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Coal purchases |  |  | - |  |  |  | 70 |  |  |  | - |  |  |  | 70 |
Power purchases |  |  | 2 |  |  |  | - |  |  |  | - |  |  |  | 2 |
Natural gas purchases and sales |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |
Heavy fuel oil purchases |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Foreign exchange forwards |  |  | - |  |  |  | 29 |  |  |  | - |  |  |  | 29 |
|  |  | 2 |  |  |  | 102 |  |  |  | - |  |  |  | 104 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | 2 |  |  |  | 2 |  |  |  | 3 |  |  |  | 7 |
Natural gas swaps, futures, forwards, physical contracts and related transportation |  |  | 1 |  |  |  | 36 |  |  |  | 18 |  |  |  | 55 |
|  |  | 3 |  |  |  | 38 |  |  |  | 21 |  |  |  | 62 |
Other derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate swap |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
|  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Total assets |  |  | 5 |  |  |  | 141 |  |  |  | 21 |  |  |  | 167 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Foreign exchange forwards |  |  | - |  |  |  | 5 |  |  |  | - |  |  |  | 5 |
|  |  | - |  |  |  | 5 |  |  |  | - |  |  |  | 5 |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Coal purchases |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Power purchases |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | 1 |
Heavy fuel oil purchases |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | 1 |
Natural gas purchases and sales |  |  | 3 |  |  |  | - |  |  |  | - |  |  |  | 3 |
|  |  | 4 |  |  |  | 2 |  |  |  | - |  |  |  | 6 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | 14 |  |  |  | 6 |  |  |  | 1 |  |  |  | 21 |
Natural gas swaps, futures, forwards and physical contracts |  |  | - |  |  |  | 28 |  |  |  | 305 |  |  |  | 333 |
|  |  | 14 |  |  |  | 34 |  |  |  | 306 |  |  |  | 354 |
Total liabilities |  |  | 18 |  |  |  | 41 |  |  |  | 306 |  |  |  | 365 |
Net assets (liabilities) |  | $ | (13) |  |  | $ | 100 |  |  | $ | (285) |  |  | $ | (198) |

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As at |  | December 31, 2017 |
millions of Canadian dollars |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps |  | $ | 5 |  |  | $ | - |  |  | $ | - |  |  | $ | 5 |
Foreign exchange forwards |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |
|  |  | 5 |  |  |  | 2 |  |  |  | - |  |  |  | 7 |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps and forwards |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Coal purchases |  |  | - |  |  |  | 127 |  |  |  | - |  |  |  | 127 |
Power purchases |  |  | 5 |  |  |  | - |  |  |  | - |  |  |  | 5 |
Natural gas purchases and sales |  |  | - |  |  |  | 5 |  |  |  | - |  |  |  | 5 |
Heavy fuel oil purchases |  |  | 4 |  |  |  | 8 |  |  |  | - |  |  |  | 12 |
Foreign exchange forwards |  |  | - |  |  |  | 32 |  |  |  | - |  |  |  | 32 |
|  |  | 9 |  |  |  | 172 |  |  |  | - |  |  |  | 181 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | - |  |  |  | 3 |  |  |  | 9 |  |  |  | 12 |
Natural gas swaps, futures, forwards, physical contracts and related transportation |  |  | - |  |  |  | 26 |  |  |  | 25 |  |  |  | 51 |
|  |  | - |  |  |  | 29 |  |  |  | 34 |  |  |  | 63 |
Other derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate swap |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |
|  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | 2 |
Total assets |  |  | 14 |  |  |  | 205 |  |  |  | 34 |  |  |  | 253 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash flow hedges |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps |  |  | 2 |  |  |  | - |  |  |  | - |  |  |  | 2 |
Foreign exchange forwards |  |  | - |  |  |  | 5 |  |  |  | - |  |  |  | 5 |
|  |  | 2 |  |  |  | 5 |  |  |  | - |  |  |  | 7 |
Regulatory deferral |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power purchases |  |  | 3 |  |  |  | - |  |  |  | - |  |  |  | 3 |
Natural gas purchased and sales |  |  | 5 |  |  |  | 1 |  |  |  | - |  |  |  | 6 |
Foreign exchange forwards |  |  | - |  |  |  | 4 |  |  |  | - |  |  |  | 4 |
|  |  | 8 |  |  |  | 5 |  |  |  | - |  |  |  | 13 |
HFT derivatives |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Power swaps and physical contracts |  |  | 49 |  |  |  | 5 |  |  |  | (4) |  |  |  | 50 |
Natural gas swaps, futures, forwards and physical contracts |  |  | 6 |  |  |  | 47 |  |  |  | 187 |  |  |  | 240 |
|  |  | 55 |  |  |  | 52 |  |  |  | 183 |  |  |  | 290 |
Total liabilities |  |  | 65 |  |  |  | 62 |  |  |  | 183 |  |  |  | 310 |
Net assets (liabilities) |  | $ | (51) |  |  | $ | 143 |  |  | $ | (149) |  |  | $ | (57) |

The change in the fair value of the Level 3 financial assets for the year ended December 31, 2018 was as follows:

|  | HFT Derivatives |
millions of Canadian dollars |  | Power |  |  | Natural gas |  |  | Total |
Balance, January 1, 2018 |  | $ | 9 |  |  | $ | 25 |  |  | $ | 34 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues |  |  | (6) |  |  |  | (7) |  |  |  | (13) |
Balance, December 31, 2018 |  | $ | 3 |  |  | $ | 18 |  |  | $ | 21 |

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The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2018 was as follows:

|  | HFT Derivatives |
millions of Canadian dollars |  | Power |  |  | Natural gas |  |  | Total |
Balance, January 1, 2018 |  | $ | (4) |  |  | $ | 187 |  |  | $ | 183 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues |  |  | 5 |  |  |  | 118 |  |  |  | 123 |
Balance, December 31, 2018 |  | $ | 1 |  |  | $ | 305 |  |  | $ | 306 |

The Company evaluates the observable inputs of market data on a quarterly basis in order to determine if transfers between levels is appropriate. For the year ended December 31, 2018, there were no transfers between levels.

Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives include third-party-sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Where possible, Emera also sources multiple broker prices in an effort to evaluate and substantiate these unobservable inputs. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement.

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The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:

As at |  | December 31, 2018 |
millions of Canadian dollars |  | Fair Value |  |  | Valuation Technique |  | Unobservable Input |  | Range |  | Weighted average |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |
HFT derivatives – |  | $ | 3 |  |  | Modelled pricing |  | Third-party pricing |  | $24.31 - $50.29 |  |  | $31.43 |
Power swaps and |  |  |  |  |  |  |  | Probability of default |  | 0.03% - 0.13% |  |  | 0.13% |
physical contracts |  |  |  |  |  |  |  | Discount rate |  | 0.03% - 2.19% |  |  | 1.45% |
|  |  |  |  |  |  |  | Correlation factor |  | 84.98% - 84.98% |  |  | 84.98% |
HFT derivatives – |  |  | 8 |  |  | Modelled pricing |  | Third-party pricing |  | $1.80 - $12.21 |  |  | $4.75 |
Natural gas swaps, futures, |  |  |  |  |  |  |  | Probability of default |  | 0.01% - 2.94% |  |  | 0.24% |
forwards, physical contracts |  |  |  |  |  |  |  | Discount rate |  | 0.01% - 30.62% |  |  | 4.25% |
and related transportation |  |  | 10 |  |  | Modelled pricing |  | Third-party pricing |  | $1.95 - $12.90 |  |  | $8.68 |
|  |  |  |  |  |  |  | Basis adjustment |  | $0.07 - $3.43 |  |  | $1.88 |
|  |  |  |  |  |  |  | Probability of default |  | 0.01% - 3.20% |  |  | 0.57% |
|  |  |  |  |  |  |  | Discount rate |  | 0.01% - 7.61% |  |  | 0.42% |
Total assets |  | $ | 21 |  |  |  |  |  |  |  |  |  |  |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |
HFT derivatives – |  | $ | 1 |  |  | Modelled pricing |  | Third-party pricing |  | $20.80 - $50.29 |  |  | $26.38 |
Power swaps and |  |  |  |  |  |  |  | Probability of default |  | 0.08% - 0.29% |  |  | 0.15% |
physical contracts |  |  |  |  |  |  |  | Discount rate |  | 0.03% - 2.99% |  |  | 1.65% |
|  |  |  |  |  |  |  | Correlation factor |  | 84.98% - 84.98% |  |  | 84.98% |
HFT derivatives – |  |  | 286 |  |  | Modelled pricing |  | Third-party pricing |  | $1.48 - $12.90 |  |  | $5.75 |
Natural gas swaps, futures, |  |  |  |  |  |  |  | Own credit risk |  | 0.01% - 2.94% |  |  | 0.09% |
forwards and physical contracts |  |  |  |  |  |  |  | Discount rate |  | 0.01% - 11.96% |  |  | 2.35% |
|  |  | 19 |  |  | Modelled pricing |  | Third-party pricing |  | $2.15 - $13.18 |  |  | $7.54 |
|  |  |  |  |  |  |  | Basis adjustment |  | $0.07 - $3.43 |  |  | $2.67 |
|  |  |  |  |  |  |  | Own credit risk |  | 0.01% - 2.76% |  |  | 0.10% |
|  |  |  |  |  |  |  | Discount rate |  | 0.01% - 7.61% |  |  | 1.38% |
Total liabilities |  | $ | 306 |  |  |  |  |  |  |  |  |  |  |
Net assets (liabilities) |  | $ | (285) |  |  |  |  |  |  |  |  |  |  |

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As at |  | December 31, 2017 |
millions of Canadian dollars |  | Fair Value |  |  | Valuation Technique |  | Unobservable Input |  | Range |  | Weighted average |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |
HFT derivatives – |  | $ | 1 |  |  | Modelled pricing |  | Third-party pricing |  | $24.88 - $117.90 |  |  | $92.93 |
Power swaps and |  |  |  |  |  |  |  | Probability of default |  | 0.00% - 0.01% |  |  | 0.00% |
physical contracts |  |  |  |  |  |  |  | Discount rate |  | 0.00% - 0.13% |  |  | 0.00% |
|  |  | 8 |  |  | Modelled pricing |  | Third-party pricing |  | $63.48 - $117.00 |  |  | $102.68 |
|  |  |  |  |  |  |  | Correlation factor |  | 0.94% - 0.99% |  |  | 0.96% |
|  |  |  |  |  |  |  | Probability of default |  | 0.00% - 0.00% |  |  | 0.00% |
|  |  |  |  |  |  |  | Discount rate |  | 0.00% - 0.00% |  |  | 0.00% |
HFT derivatives – |  |  | 18 |  |  | Modelled pricing |  | Third-party pricing |  | $2.06 - $8.24 |  |  | $3.61 |
Natural gas swaps, |  |  |  |  |  |  |  | Probability of default |  | 0.00% - 0.05% |  |  | 0.00% |
futures, forwards, |  |  |  |  |  |  |  | Discount rate |  | 0.00% - 0.29% |  |  | 0.06% |
physical contracts |  |  | 7 |  |  | Modelled pricing |  | Third-party pricing |  | $2.04 - $12.52 |  |  | $6.42 |
and related transportation |  |  |  |  |  |  |  | Basis adjustment |  | 0.08% - 0.71% |  |  | 0.52% |
|  |  |  |  |  |  |  | Probability of default |  | 0.00% - 0.00% |  |  | 0.00% |
|  |  |  |  |  |  |  | Discount rate |  | 0.00% - 0.09% |  |  | 0.01% |
Total assets |  | $ | 34 |  |  |  |  |  |  |  |  |  |  |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |
HFT derivatives – |  | $ | (6) |  |  | Modelled pricing |  | Third-party pricing |  | $24.88 - $117.90 |  |  | $95.46 |
Power swaps and |  |  |  |  |  |  |  | Own credit risk |  | 0.00% - 0.01% |  |  | 0.00% |
physical contracts |  |  |  |  |  |  |  | Discount rate |  | 0.00% - 0.13% |  |  | 0.00% |
|  |  | 2 |  |  | Modelled pricing |  | Third-party pricing |  | $94.5 - $117.00 |  |  | $105.52 |
|  |  |  |  |  |  |  | Correlation factor |  | 0.94% - 0.99% |  |  | 0.96% |
|  |  |  |  |  |  |  | Probability of default |  | 0.00% - 0.00% |  |  | 0.00% |
|  |  |  |  |  |  |  | Discount rate |  | 0.00% - 0.00% |  |  | 0.00% |
HFT derivatives – |  |  | 172 |  |  | Modelled pricing |  | Third-party pricing |  | $1.89 - $11.81 |  |  | $4.64 |
Natural gas swaps, futures, |  |  |  |  |  |  |  | Own credit risk |  | 0.00% - 0.00% |  |  | 0.00% |
forwards and physical contracts |  |  |  |  |  |  |  | Discount rate |  | 0.00% - 0.12% |  |  | 0.02% |
|  |  | 15 |  |  | Modelled pricing |  | Third-party pricing |  | $2.15 - $12.52 |  |  | $8.94 |
|  |  |  |  |  |  |  | Basis adjustment |  | 0.08% - 0.71% |  |  | 0.53% |
|  |  |  |  |  |  |  | Own credit risk |  | 0.00% - 0.00% |  |  | 0.00% |
|  |  |  |  |  |  |  | Discount rate |  | 0.00% - 0.08% |  |  | 0.01% |
Total liabilities |  | $ | 183 |  |  |  |  |  |  |  |  |  |  |
Net assets (liabilities) |  | $ | (149) |  |  |  |  |  |  |  |  |  |  |

The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following:

As at |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
millions of Canadian dollars |  | Carrying Amount |  |  | Fair Value |  |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |
December 31, 2018 |  | $ | 15,411 |  |  | $ | 15,908 |  |  | $ | - |  |  | $ | 14,991 |  |  | $ | 917 |  |  | $ | 15,908 |
December 31, 2017 |  | $ | 13,881 |  |  | $ | 15,217 |  |  | $ | 69 |  |  | $ | 14,346 |  |  | $ | 802 |  |  | $ | 15,217 |

The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations. An after-tax foreign currency loss of $122 million was recorded in Other Comprehensive Income for the year ended December 31, 2018 (2017 – $97 million gain after-tax). There was no ineffectiveness for the year ended December 31, 2018 (2017 – nil).

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14. REGULATORY ASSETS AND LIABILITIES

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates or tolls collected from customers. Management believes existing regulatory assets are probable for recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income.

Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.

For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator.

Regulatory Assets and Liabilities

As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |
Regulatory assets |  |  |  |  |  |  |  |
Deferred income tax regulatory assets |  | $ | 775 |  |  | $ | 667 |
Pension and post-retirement medical plan (1) |  |  | 453 |  |  |  | 380 |
Cost recovery clauses |  |  | 75 |  |  |  | 17 |
Environmental remediations |  |  | 31 |  |  |  | 41 |
Hurricane Matthew restoration |  |  | 28 |  |  |  | 28 |
Stranded cost recovery |  |  | 28 |  |  |  | 25 |
Unamortized defeasance costs |  |  | 26 |  |  |  | 32 |
Demand side management (“DSM”) deferral |  |  | 24 |  |  |  | 28 |
Deferrals related to derivative instruments |  |  | 10 |  |  |  | 15 |
Storm reserve |  |  | 4 |  |  |  | 59 |
Other |  |  | 115 |  |  |  | 119 |
|  | $ | 1,569 |  |  | $ | 1,411 |
Current |  | $ | 165 |  |  | $ | 138 |
Long-term |  |  | 1,404 |  |  |  | 1,273 |
Total regulatory assets |  | $ | 1,569 |  |  | $ | 1,411 |
Regulatory liabilities |  |  |  |  |  |  |  |
Deferred income tax regulatory liabilities |  |  | 1,218 |  |  |  | 1,116 |
Accumulated reserve - cost of removal |  |  | 955 |  |  |  | 894 |
Regulated fuel adjustment mechanism |  |  | 161 |  |  |  | 177 |
Deferrals related to derivative instruments |  |  | 116 |  |  |  | 182 |
Storm reserve |  |  | 76 |  |  |  | - |
Cost recovery clauses |  |  | 30 |  |  |  | 51 |
Self-insurance fund (note 31) |  |  | 30 |  |  |  | 28 |
Other |  |  | 24 |  |  |  | 20 |
|  | $ | 2,610 |  |  | $ | 2,468 |
Current |  | $ | 251 |  |  | $ | 226 |
Long-term |  |  | 2,359 |  |  |  | 2,242 |
Total regulatory liabilities |  | $ | 2,610 |  |  | $ | 2,468 |

(1) The December 31, 2017 pension and post-retirement medical plan regulatory asset includes a prior period reclassification of $35 million from AOCI, for changes in unrecognized pension and post-retirement benefit costs to be consistent with current year presentation. Refer to note 10 for further details.

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Deferred Income Tax Regulatory Assets and Liabilities

To the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator.

In 2017, as a result of enactment of the US Tax Cuts and Jobs Act of 2017, the Company revalued its United States deferred income tax assets and liabilities based on the new 21 per cent tax rate. The Company reduced its US regulated net deferred income tax liabilities by $1.1 billion and recorded an equivalent regulatory liability since the benefit of lower US taxes is expected to be returned to customers over time as required by the Act or by order of the applicable regulator.

Pension and Post-Retirement Medical Plan

This asset is primarily related to the deferred costs of pension and post-retirement benefits at Emera Florida and New Mexico, and Emera Maine. It is included in rate base and earns a rate of return as permitted by the FPSC, New Mexico Public Regulation Commission (“NMPRC”) and Maine Public Utilities Commission (“MPUC”), as applicable. It is amortized over the remaining service life of plan participants.

Cost Recovery Clauses

These assets and liabilities are related to Tampa Electric, PGS and NMGC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year.

Environmental Remediations

This asset is primarily related to PGS costs associated with the environmental remediation at Manufactured Gas Plant (“MGP”) sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC.

Hurricane Matthew Restoration

This asset represents restoration costs incurred by GBPC in 2016 associated with Hurricane Matthew. The asset is being amortized over five years and is included in rate base. The Grand Bahama Port Authority (“GBPA”) has approved full recovery of these storm restoration costs.

Stranded Cost Recovery

Due to the decommissioning of a GBPC steam turbine during 2012, the GBPA approved the recovery of a $21 million USD stranded cost through electricity rates; it is included in rate base for 2018 and 2017 and is expected to be included in future years.

Unamortized Defeasance Costs

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities held in trust that provide the principal and interest streams to match the related defeased debt, which as at December 31, 2018, totalled $759 million (2017 – $726 million). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amortized over the life of the defeased debt as permitted by the Nova Scotia Utility and Review Board (“UARB”).

DSM Deferral

The UARB approved the implementation of the 2015 DSM deferral set at $35 million for 2015 and recoverable from customers over an eight year period beginning in 2016.

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The UARB directed EfficiencyOne to review the financing options through which EfficiencyOne would borrow the 2015 deferral amount from a commercial lender in order to repay NSPI the amount it expended on behalf of its customers in 2015. In December 2016, EfficiencyOne secured financing and $31 million was advanced to NSPI to finance the 2015 DSM deferral. As NSPI collects the associated amounts from customers over the next six years, it will repay the balance to EfficiencyOne. This has been set up as a liability in “Other long-term liabilities” with the current portion of the liability included in “Other current liabilities” on the Consolidated Balance Sheets.

Deferrals Related to Derivative Instruments

Tampa Electric, PGS, NMGC, NSPI and GBPC defer changes in fair value of derivatives that are documented as economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved by the respective regulators. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory or property, plant and equipment, depending on the nature of the item being economically hedged. Tampa Electric deferrals related to derivative instruments are recovered through cost-recovery mechanisms on a dollar-for-dollar basis in the year following the settlement of the derivative position.

Accumulated Reserve – Cost of Removal

This regulatory liability represents the non-ARO COR reserve in Tampa Electric and NSPI. AROs are costs for legally required removal of property, plant and equipment. Non-ARO COR represent estimated funds received from customers through depreciation rates to cover future non-legally required cost of removal of property, plant and equipment, net of salvage value upon retirement, which reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as new assets are put into service.

Regulated Fuel Adjustment Mechanism

This regulated liability is the difference between actual fuel costs and amounts recovered from NSPI customers through electricity rates in a given year, and are deferred to a fuel adjustment mechanism (“FAM”) regulatory asset or liability and recovered from or returned to customers in a subsequent year. For the years 2017 to 2019, differences between actual fuel costs and fuel revenues recovered from customers will be recovered or returned to customers after 2019, as required under the Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”).

Storm Reserve

The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric and PGS systems. As allowed by the FPSC, if the charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory asset. Tampa Electric and PGS can petition the FPSC to seek recovery of restoration costs over a 12 month period, or longer, as determined by the FPSC, as well as replenish the reserve.

On September 10, 2017, Tampa Electric was impacted by Hurricane Irma and incurred total restoration costs of approximately $102 million USD. The amount charged to the storm reserve exceeded the balance in the reserve by $47 million USD, which was recorded as a regulatory asset on the balance sheet. This regulated asset was included in rate base. On December 28, 2017, Tampa Electric petitioned the FPSC for recovery of estimated restoration costs in excess of the storm reserve for several named storms and to replenish the reserve to the $56 million USD level that existed at October 31, 2013. On March 1, 2018, the FPSC approved a settlement agreement authorizing the utility to net the amount of storm cost recovery against its return of estimated 2018 US tax reform benefits to customers, effective April 1, 2018. At December 31, 2018, Tampa Electric’s storm reserve liability was $56 million USD.

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Regulatory Environments

Emera Florida and New Mexico

Tampa Electric and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by the FERC. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to their cost of providing service, plus an appropriate return on invested capital.

Tampa Electric

Tampa Electric’s approved regulated return on equity (“ROE”) range is 9.25 per cent to 11.25 per cent based on an allowed equity capital structure of 54 per cent. An ROE of 10.25 per cent is used for the calculation of the return on investments for clauses.

Tampa Electric has a fuel recovery clause approved by the FPSC, allowing it the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs including a return on capital invested. Differences between the prudently incurred fuel costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or liability and recovered from or returned to customers in a subsequent year.

In September 2017, Tampa Electric announced its intention to invest approximately $850 million USD over four years in new utility-scale solar photovoltaic projects across its service territory. On November 6, 2017, the FPSC approved a settlement agreement allowing a solar base rate adjustment (“SoBRA”) that provides for the recovery, upon in-service, of up to 600 MW of investments in utility-scale solar projects phased in from late 2018 through early 2021. On May 8, 2018, the FPSC approved Tampa Electric’s first SoBRA. This SoBRA represents 145 MW and $24 million USD annually in estimated revenue requirements and Tampa Electric began collecting these revenues in September 2018. On October 29, 2018, the FPSC approved Tampa Electric’s second SoBRA. This SoBRA represents 260 MW and $46 million USD annually in estimated revenue requirements and Tampa Electric began collecting these revenues in January 2019.

As discussed in the Storm Reserve section above, in September 2017, Tampa Electric was impacted by Hurricane Irma and incurred restoration costs in excess of the balance in its storm reserve. Tampa Electric petitioned the FPSC for recovery of estimated restoration costs in excess of the storm reserve for several named storms and to replenish the reserve. The FPSC approved a settlement agreement filed by Tampa Electric authorizing the utility to net the estimated amount of storm cost recovery against its return of estimated 2018 US tax reform benefits to customers, effective April 1, 2018. In Q1 2018, Tampa Electric recorded OM&G expense and a regulatory liability of $19 million USD to offset tax reform benefits. This deferral was amortized over the balance of the year as a credit against recognition of storm expense. In total, OM&G expense due to the allowed netting of the storm cost recovery with tax reform benefits, net of amortization of first quarter tax reform benefits, was approximately $103 million USD for the year ended December 31, 2018. Tampa Electric’s final storm costs subject to netting will be determined in a separate regulatory proceeding in 2019. Any difference will be trued up and returned to customers in 2020. On August 20, 2018, the FPSC approved a reduction in base rates of $103 million USD annually beginning in 2019 as a result of lower tax expense.

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PGS

The approved ROE range for PGS is 9.25 per cent to 11.75 per cent, based on an allowed equity capital structure of 54.7 per cent. Absent any rate case filing, the bottom of the range will increase to 9.75 per cent in 2021. An ROE of 10.75 per cent is used for the calculation of return on investments for clauses.

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its purchased gas adjustment clause. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap approved annually by the FPSC.

The FPSC annually approves cost-recovery rates for conservation costs including a return on capital invested incurred in developing and implementing energy conservation programs. In 2012, the FPSC approved a new Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. The FPSC approved a replacement program of approximately 5 per cent, or 800 kilometres, of the PGS system at a cost of approximately $80 million USD over a 10-year period. As part of the depreciation study settlement agreement approved by the FPSC in February 2017, the Cast Iron/Bare Steel clause was expanded to allow recovery of accelerated replacement of certain obsolete pipe.

On February 7, 2017, the FPSC approved a settlement agreement which resulted in new depreciation rates that reduce annual depreciation by $16 million USD and accelerate the amortization of the regulated asset related to the MGP environmental remediation costs. As part of the settlement, PGS and the Office of Public Counsel agreed that at least $32 million USD of PGS’s regulatory asset associated with the environmental liability for current and future remediation costs related to former MGP sites will be amortized over the period 2016 through 2020, with at least $21 million USD amortized over a two year recovery period beginning in 2016. In 2017 and 2016, PGS recorded $5 million USD and $16 million USD, respectively, of this amortization expense.

The 2017 PGS settlement agreement does not contain a provision for tax reform. On September 12, 2018, the FPSC approved a settlement agreement filed by PGS authorizing the utility to amortize $11 million USD of its MGP environmental regulatory asset and net it against its estimated 2018 tax reform benefits. Beginning in January 2019, PGS will lower base rates by $12 million USD to reflect the impact of tax reform and reduce depreciation rates by $10 million USD in accordance with the settlement agreement.

PGS is permitted to initiate a general base rate proceeding if it forecasts that ROE will fall below its allowed range.

NMGC

The approved ROE for NMGC is 10 per cent, on an allowed equity capital structure of 52 per cent. NMGC’s rates were established in a 2012 rate case settlement and were frozen until December 31, 2017 per the June 2016 NMPRC order (the “Order”) approving Emera’s acquisition of TECO Energy. NMGC filed a rate case, including the prospective impact of tax reform, on February 26, 2018. A hearing in the rate case was held on September 24, 2018, where an uncontested stipulation on the rate request was presented. A second hearing on the rate case related to 2018 tax reform benefits was held on December 17, 2018. As of December 31, 2018, NMGC recorded a regulatory liability of $8 million USD to reflect 2018 tax reform benefits. A decision by the NMPRC on the rate case and on 2018 tax reform benefits is expected in 2019.

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NMGC recovers gas supply costs through a purchased gas adjustment clause (“PGAC”). This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust the charges based on the next month’s expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. In December 2016, NMGC received approval of its PGAC Continuation Filing for the four-year period ending December 2020.

NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “Public Utilities Act”) and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s approved regulated ROE range for 2018 and 2017 was 8.75 per cent to 9.25 per cent based on an actual five quarter average regulated common equity component of up to 40 per cent. NSPI has a FAM, which enables it to seek recovery of fuel costs through regularly scheduled rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

The Electricity Plan Implementation (2015) Act, (“Electricity Plan Act”), was enacted by the Province of Nova Scotia in December 2015, which required NSPI to file a three-year stability plan for fuel costs and a General Rate Application (“GRA”) for non-fuel costs if required. In July 2016, the UARB approved a Consensus Agreement between NSPI and customer representatives related to the Rate Stability Plan for fuel costs for 2017 through 2019 which resulted in an average annual increase of 1.1 per cent for each of these three years. Subsequently, certain customer representatives requested changes resulting in amended rates that were approved by the UARB in November 2016 and result in an average annual rate increase of 1.5 per cent for each of these three years.

In September 2017, the UARB approved NSPI’s interim assessment payment to NSPML of the costs associated with the Maritime Link when it is in service. The Maritime Link entered service on January 15, 2018 and NSPI started paying the UARB approved interim assessment payments. As of December 31, 2018, $96 million has been paid to NSPML. The UARB approved annual payment for 2019 is $111 million. The payments are subject to a holdback of $10 million in each of 2018 and 2019 pending UARB agreement that a minimum of $10 million per year in benefits from the Maritime Link are realized for NSPI customers. If the $10 million in benefits is realized, the UARB will direct NSPI to pay the $10 million to NSPML for that year. If not realized, then the UARB will direct NSPI to pay to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM. As of December 31, 2018, NSPI has recorded a $2 million holdback payable to NSPML.

In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payment reflects a $53 million reduction in NSPML’s assessment in each of 2018 and 2019, related to depreciation and amortization expenses. As these amounts are included in NSPI’s 2017, 2018 and 2019 fuel rates and are being recovered from customers, NSPI is providing a credit to customers, including interest, as the payments from NSPI to NSPML are not required in those years. In 2018, $17 million was refunded. The credit to customers will be approximately $36 million in 2019 and $53 million in 2020.

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After 2019 and the Rate Stability Plan, the timing and amounts payable to NSPML and NSPI’s future rate recoveries of the Maritime Link costs will be subject to regulatory filings with the UARB, with expected filings in 2019 and 2020.

Emera Maine

Emera Maine’s distribution operations and stranded cost recoveries are regulated by the MPUC. The transmission operations are regulated by the FERC. Rates for these are established in distinct regulatory proceedings. US tax reform benefits, resulting from the lower tax rate, were reflected in distribution and transmission rates effective July 1, 2018, with other components being deferred to be addressed in future regulatory proceedings.

Distribution Operations

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. In June 2018, the MPUC approved a 5.3 per cent distribution rate increase. This increase was effective July 1, 2018 and is based on a 9.35 per cent ROE and a common equity component of 49 per cent. Prior to July 1, 2018, the allowed ROE was 9.0 per cent, on a common equity component of 49 per cent.

Transmission Operations

Emera Maine’s transmission operations are split between two districts; Bangor Hydro District and Maine Public Service (“MPS”). Bangor Hydro District local transmission rates are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. The allowed ROE for Bangor Hydro District local transmission operations for 2018 and 2017 is 10.57 per cent. Bangor Hydro District’s bulk transmission assets are managed by ISO-New England (“ISO-NE”) as part of a region-wide pool of assets. The allowed ROE range for Bangor Hydro bulk transmission assets is 11.07 to 11.74 per cent for 2018 and 2017.

MPS District local transmission rates are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers based on a formula utilizing prior year actual transmission investments and expenses. The current allowed ROE for transmission operations is 9.6 per cent (2017 – 9.6 per cent).

Stranded Cost Recoveries

Stranded cost recoveries in Maine are set by the MPUC. Electric utilities are permitted to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC.

The Barbados Light & Power Company Limited

BLPC is regulated by the Fair Trading Commission, an independent regulator, under the Utilities Regulation (Procedural) Rules 2003. The government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028.

BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. BLPC’s approved regulated return on rate base was 10 per cent for 2018 and 2017.

All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The approved calculation of the fuel charge is adjusted monthly.

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In December 2018, the Government of Barbados signed the Income Tax Amendment Act into law. This legislation which is effective January 1, 2019, created a new corporate income tax rate schedule and eliminated certain tax credits. At the date of enactment, BLPC was required to remeasure its deferred income tax liability at the new lower corporate income tax rate, resulting in recognition of an income tax recovery of $9.6 million USD of which $6.9 million USD was deferred as a regulatory liability.

Grand Bahama Power Company Limited

GBPC is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass-through mechanism and flexible tariff adjustment policy to ensure that fuel costs are recovered and a reasonable return earned. GBPC’s approved regulated return on rate base was 8.5 per cent for 2018 (2017 - 8.8 per cent). In December 2018, the GBPA approved GBPC’s regulated return on rate base of 8.44 per cent for 2019.

In December 2016, the GBPA approved that over a five-year period, 2017 to 2021, the all-in rate for electricity (fuel and base rates) will be held at 2016 levels. Any over-recovery of fuel costs during this period will be applied to the Hurricane Matthew regulatory deferral, until such time as the deferral is recovered. Should GBPC recover funds in excess of the Hurricane Matthew regulatory deferral, the excess will be placed in a new storm reserve. If balances remain within the Hurricane Matthew deferral at the end of five years, GBPC will have the opportunity to request recovery from customers in future rates.

Dominica Electricity Services Ltd

Domlec is regulated by the Independent Regulatory Commission, Dominica. On October 7, 2013, the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014, for a period of 25 years. Domlec’s approved allowable regulated return on rate base was 15 per cent for 2018 and 2017.

Domlec fuel costs are passed to customers through a fuel pass-through mechanism which provides the opportunity to recover substantially all fuel costs in a timely manner.

Dominica experienced unprecedented damage as a result of Hurricane Maria in September 2017, reducing the customer base from approximately 36,000 to 26,000 at December 31, 2018. Many homes were destroyed and have not been rebuilt at this time. Domlec has fully restored power to all customers who request power and are able to receive it. Domlec maintains insurance for its generation fleet and, subsequent to Hurricane Maria, has obtained specialized insurance for its transmission and distribution networks.

Brunswick Pipeline

Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Canaport™ re-gasified liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25-year firm service agreement commencing in July 2009 with Repsol Energy Canada. The pipeline is considered a Group II pipeline regulated by the National Energy Board (“NEB”). The NEB Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the NEB Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.

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15. RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies are as follows:

● |  | Transactions between NSPI and NSPML related to the Maritime Link assessment are reported in the Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $97 million for the year ended December 31, 2018 (2017 - nil). NSPML is accounted for as an equity investment and therefore, the corresponding earnings related to this revenue are reflected in Income from equity investments.

● |  | Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $29 million for the year ended December 31, 2018 (2017 - $28 million).

There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Consolidated Balance Sheets as at December 31, 2018 and at December 31, 2017.

16. RECEIVABLES AND OTHER CURRENT ASSETS

Receivables and other current assets consisted of the following:

As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |
Customer accounts receivable – billed |  |  | $ 844 |  |  |  | $ 805 |
Customer accounts receivable – unbilled |  |  | 296 |  |  |  | 278 |
Allowance for doubtful accounts |  |  | (11) |  |  |  | (12) |
Other receivables |  |  | 86 |  |  |  | 70 |
Capitalized transportation capacity (1) |  |  | 179 |  |  |  | 89 |
Income tax receivable |  |  | 175 |  |  |  | 24 |
Prepaid expenses |  |  | 42 |  |  |  | 59 |
Net investment in direct financing lease (note 20) |  |  | 9 |  |  |  | 8 |
Due from related parties (note 15) |  |  | - |  |  |  | 5 |
|  |  | $ 1,620 |  |  |  | $ 1,326 |

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

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17. HELD FOR SALE

On November 26, 2018, Emera announced an agreement to sell its three NEGG facilities for $590 million USD plus a final working capital adjustment made on close. Proceeds from the sale of the NEGG facilities will be used to reduce corporate level debt and support capital investment opportunities within the regulated utility business. The transaction is expected to close in the first quarter of 2019 and is subject to certain regulatory approvals including approval of the FERC. The applicable provisions of the Hart-Scott-Rodino Antitrust Act have been satisfied.

As at December 31, 2018, the assets of the NEGG facilities were classified as held for sale and were measured at the lower of their carrying value or fair value less costs to sell. The measurement did not result in a fair value adjustment and the assets are no longer being depreciated. Included in assets held for sale on the Consolidated Balance Sheets was $777 million ($570 million USD) related to Property, plant and equipment. The NEGG operations are included within the Company’s Emera Energy segment.

18. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following regulated and non-regulated assets:

As at millions of Canadian dollars |  | Estimated useful life |  | December 31 2018 |  |  | December 31 2017 |
Generation (1) |  | 3 to 131 |  |  | $ 11,092 |  |  |  | $ 11,010 |
Transmission |  | 11 to 80 |  |  | 3,047 |  |  |  | 2,786 |
Distribution |  | 4 to 80 |  |  | 6,348 |  |  |  | 5,660 |
Gas transmission and distribution |  | 7 to 85 |  |  | 3,398 |  |  |  | 2,867 |
General plant and other |  | 2 to 60 |  |  | 2,158 |  |  |  | 1,874 |
Total cost |  |  |  |  | 26,043 |  |  |  | 24,197 |
Less: Accumulated depreciation (1) |  |  |  |  | (8,567) |  |  |  | (7,824) |
|  |  |  |  | 17,476 |  |  |  | 16,373 |
Construction work in progress |  |  |  |  | 1,236 |  |  |  | 622 |
Net book value |  |  |  |  | $ 18,712 |  |  |  | $ 16,995 |

(1) On November 26, 2018, the Company announced an agreement to sell the NEGG facilities and as of December 31, 2018, the Company has classified these assets as held for sale. As of December 31, 2017, these assets were recorded within Property, Plant and Equipment on the Consolidated Balance Sheets. Refer to note 17 for additional information.

19. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, Maine, Connecticut, Massachusetts, Rhode Island, New Mexico, Barbados, Dominica and Grand Bahama Island.

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Benefit Obligation and Plan Assets

The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:

For the millions of Canadian dollars |  |  |  |  | 2018 |  |  | Year ended December 31 2017 |
Change in Projected Benefit Obligation (“PBO”) and Accumulated Post-retirement Benefit Obligation (“APBO”) |  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Balance, January 1 |  |  | $ 2,683 |  |  |  | $ 356 |  |  |  | $ 2,607 |  |  |  | $ 358 |
Service cost |  |  | 51 |  |  |  | 6 |  |  |  | 49 |  |  |  | 5 |
Plan participant contributions |  |  | 8 |  |  |  | 5 |  |  |  | 8 |  |  |  | 4 |
Interest cost |  |  | 95 |  |  |  | 13 |  |  |  | 99 |  |  |  | 14 |
Benefits paid |  |  | (143) |  |  |  | (33) |  |  |  | (129) |  |  |  | (27) |
Actuarial (gains) losses |  |  | (133) |  |  |  | (25) |  |  |  | 171 |  |  |  | 25 |
Settlements and curtailments |  |  | (18) |  |  |  | - |  |  |  | (35) |  |  |  | - |
Foreign currency translation adjustment |  |  | 107 |  |  |  | 28 |  |  |  | (87) |  |  |  | (23) |
Balance, December 31 |  |  | 2,650 |  |  |  | 350 |  |  |  | 2,683 |  |  |  | 356 |
Change in plan assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance, January 1 |  |  | 2,408 |  |  |  | 45 |  |  |  | 2,208 |  |  |  | 39 |
Employer contributions |  |  | 51 |  |  |  | 31 |  |  |  | 109 |  |  |  | 27 |
Plan participant contributions |  |  | 8 |  |  |  | 5 |  |  |  | 8 |  |  |  | 4 |
Benefits paid |  |  | (143) |  |  |  | (33) |  |  |  | (129) |  |  |  | (27) |
Actual return on assets, net of expenses |  |  | (105) |  |  |  | (3) |  |  |  | 313 |  |  |  | 5 |
Settlements and curtailments |  |  | (18) |  |  |  | - |  |  |  | (34) |  |  |  | - |
Foreign currency translation adjustment |  |  | 99 |  |  |  | 4 |  |  |  | (67) |  |  |  | (3) |
Balance, December 31 |  |  | 2,300 |  |  |  | 49 |  |  |  | 2,408 |  |  |  | 45 |
Funded status, end of year |  |  | $ (350) |  |  |  | $ (301) |  |  |  | $ (275) |  |  |  | $ (311) |

Plans with PBO/APBO in Excess of Plan Assets

The aggregate financial position for all pension plans where the PBO or, for post-retirement benefit plans, the APBO exceeds the plan assets for the years ended December 31 is as follows:

millions of Canadian dollars |  |  |  |  | 2018 |  |  | 2017 |
|  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
PBO/APBO |  | $ | 2,623 |  |  | $ | 318 |  |  | $ | 2,655 |  |  | $ | 325 |
Fair value of plan assets |  |  | 2,264 |  |  |  | 6 |  |  |  | 2,370 |  |  |  | 6 |
Funded status |  | $ | (359) |  |  | $ | (312) |  |  | $ | (285) |  |  | $ | (319) |

Plans with Accumulated Benefit Obligation (“ABO”) in Excess of Plan Assets

The ABO for the defined benefit pension plans was $2,527 million as at December 31, 2018 (2017 – $2,561 million). The aggregate financial position for those plans with an ABO in excess of the plan assets for the years ended December 31 is as follows:

millions of Canadian dollars |  | 2018 |  |  | 2017 |
|  | Defined benefit pension plans |  |  | Defined benefit pension plans |
ABO |  | $ | 2,504 |  |  | $ | 1,608 |
Fair value of plan assets |  |  | 2,264 |  |  |  | 1,409 |
Funded status |  | $ | (240) |  |  | $ | (199) |

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Balance Sheet

The amounts recognized in the Consolidated Balance Sheets consisted of the following:

As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |
|  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Other current liabilities |  | $ | (12) |  |  | $ | (19) |  |  | $ | (23) |  |  | $ | (18) |
Long-term liabilities |  |  | (347) |  |  |  | (294) |  |  |  | (264) |  |  |  | (295) |
Other long-term assets |  |  | 9 |  |  |  | 11 |  |  |  | 10 |  |  |  | - |
Amount included in deferred income tax |  |  | 5 |  |  |  | (2) |  |  |  | 2 |  |  |  | - |
AOCI, net of tax and regulatory assets |  |  | 628 |  |  |  | 60 |  |  |  | 561 |  |  |  | 74 |
Net amount recognized |  | $ | 283 |  |  | $ | (244) |  |  | $ | 286 |  |  | $ | (239) |

Amounts Recognized in AOCI and Regulatory Assets

Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory assets. The following table summarizes the change in AOCI and regulatory assets:

millions of Canadian dollars |  | Regulatory assets |  |  | Actuarial (gains) losses |  |  | Past service (gains) costs |
Defined Benefit Pension Plans (1) |  |  |  |  |  |  |  |  |  |  |  |
Balance, January 1, 2018 |  | $ | 315 |  |  | $ | 251 |  |  | $ | (3) |
Amortized in current period |  |  | (26) |  |  |  | (37) |  |  |  | 1 |
Current year addition to AOCI or regulatory assets |  |  | 73 |  |  |  | 32 |  |  |  | - |
Change in foreign exchange rate |  |  | 27 |  |  |  | - |  |  |  | - |
Balance, December 31, 2018 |  | $ | 389 |  |  | $ | 246 |  |  | $ | (2) |
Non-pension benefits plans (1) |  |  |  |  |  |  |  |  |  |  |  |
Balance, January 1, 2018 |  | $ | 78 |  |  | $ | (4) |  |  | $ | - |
Amortized in current period |  |  | 2 |  |  |  | 1 |  |  |  | - |
Current year addition to AOCI or regulatory assets |  |  | (17) |  |  |  | (4) |  |  |  | - |
Change in foreign exchange rate |  |  | 2 |  |  |  | - |  |  |  | - |
Balance, December 31, 2018 |  | $ | 65 |  |  | $ | (7) |  |  | $ | - |

(1) The January 1, 2018 balances include a prior period reclassification from AOCI to Regulatory assets, for changes in unrecognized pension and post-retirement benefit costs to be consistent with current year presentation. Refer to notes 10 and 14 for further details.

|  | 2018 |  |  | 2017 |
|  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Actuarial losses |  | $ | 246 |  |  | $ | (7) |  |  | $ | 251 |  |  | $ | (4) |
Past service (gains) costs |  |  | (2) |  |  |  | - |  |  |  | (3) |  |  |  | - |
Regulatory assets |  |  | 389 |  |  |  | 65 |  |  |  | 315 |  |  |  | 78 |
Total AOCI and regulatory assets before deferred income taxes |  |  | 633 |  |  |  | 58 |  |  |  | 563 |  |  |  | 74 |
Amount included in deferred income tax assets |  |  | (5) |  |  |  | 2 |  |  |  | (2) |  |  |  | - |
Net amount in AOCI and regulatory assets |  | $ | 628 |  |  | $ | 60 |  |  | $ | 561 |  |  | $ | 74 |

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Benefit Cost Components

Emera’s net periodic benefit cost included the following:

As at millions of Canadian dollars |  | 2018 |  |  | Year ended December 31 2017 |
|  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Service cost |  | $ | 51 |  |  | $ | 6 |  |  | $ | 49 |  |  | $ | 5 |
Interest cost |  |  | 95 |  |  |  | 13 |  |  |  | 99 |  |  |  | 14 |
Expected return on plan assets |  |  | (138) |  |  |  | (2) |  |  |  | (129) |  |  |  | (3) |
Current year amortization of: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Actuarial losses |  |  | 33 |  |  |  | (1) |  |  |  | 38 |  |  |  | 2 |
Past service costs (gains) |  |  | (1) |  |  |  | - |  |  |  | - |  |  |  | (8) |
Regulatory assets (liability) |  |  | 26 |  |  |  | (2) |  |  |  | 17 |  |  |  | (1) |
Settlement, curtailments |  |  | 4 |  |  |  | - |  |  |  | (1) |  |  |  | - |
Total |  | $ | 70 |  |  | $ | 14 |  |  | $ | 73 |  |  | $ | 9 |

The expected return on plan assets is determined based on the market-related value of plan assets of $2,223 million as at January 1, 2018 (2017 – $2,153 million), adjusted for interest on certain cash flows during the year. The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period.

Pension Plan Asset Allocations

Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a broad basket of investment and non-investment grade securities. Emera’s target asset allocation is as follows:

Canadian Pension Plans

Asset Class |  | Target Range at Market |
Short-term securities |  |  | 0% |  |  |  | to |  |  |  | 5% |
Fixed income |  |  | 35% |  |  |  | to |  |  |  | 50% |
Equities: |  |  |  |  |  |  |  |  |  |  |  |
Canadian |  |  | 12% |  |  |  | to |  |  |  | 22% |
Non-Canadian |  |  | 30% |  |  |  | to |  |  |  | 55% |

Non-Canadian Pension Plans

Asset Class |  | Target Range at Market Weighted average |
Fixed income |  |  | 48% |  |  |  | to |  |  |  | 53% |
Equities |  |  | 47% |  |  |  | to |  |  |  | 52% |

Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring companies. All pension investments are in accordance with policies approved by the respective Board of Directors of each sponsoring company.

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The following tables set out the classification of the methodology used by the Company to fair value its investments:

millions of Canadian dollars |  | NAV |  |  | Level 1 |  |  | Level 2 |  |  | Total |  |  | Percentage |
|  |  |  |  |  |  |  | December 31, 2018 |
Cash and cash equivalents |  | $ | - |  |  | $ | 30 |  |  | $ | - |  |  | $ | 30 |  |  |  | 1% |
Net in-transits |  |  | - |  |  |  | (56) |  |  |  | - |  |  |  | (56) |  |  |  | -2% |
Equity Securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canadian equity |  |  | - |  |  |  | 191 |  |  |  | - |  |  |  | 191 |  |  |  | 8% |
US equity |  |  | - |  |  |  | 330 |  |  |  | - |  |  |  | 330 |  |  |  | 14% |
Other equity |  |  | - |  |  |  | 157 |  |  |  | - |  |  |  | 157 |  |  |  | 7% |
Fixed income securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Government |  |  | - |  |  |  | - |  |  |  | 119 |  |  |  | 119 |  |  |  | 5% |
Corporate |  |  | - |  |  |  | - |  |  |  | 108 |  |  |  | 108 |  |  |  | 5% |
Other |  |  | - |  |  |  | 4 |  |  |  | 3 |  |  |  | 7 |  |  |  | - |
Mutual funds |  |  | - |  |  |  | 132 |  |  |  | - |  |  |  | 132 |  |  |  | 6% |
Other |  |  | - |  |  |  | 8 |  |  |  | 4 |  |  |  | 12 |  |  |  | 1% |
Open-ended investments measured at NAV (1) |  |  | 820 |  |  |  | - |  |  |  | - |  |  |  | 820 |  |  |  | 36% |
Common collective trusts measured at NAV (2) |  |  | 450 |  |  |  | - |  |  |  | - |  |  |  | 450 |  |  |  | 19% |
Total |  | $ | 1,270 |  |  | $ | 796 |  |  | $ | 234 |  |  | $ | 2,300 |  |  |  | 100% |
|  |  |  |  |  |  |  |  |  |  | December 31, 2017 |
Cash and cash equivalents |  | $ | - |  |  | $ | 32 |  |  | $ | - |  |  | $ | 32 |  |  |  | 1% |
Net in-transits |  |  | - |  |  |  | (36) |  |  |  | - |  |  |  | (36) |  |  |  | -1% |
Equity securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Canadian equity |  |  | - |  |  |  | 214 |  |  |  | - |  |  |  | 214 |  |  |  | 9% |
US equity |  |  | - |  |  |  | 390 |  |  |  | - |  |  |  | 390 |  |  |  | 16% |
Other equity |  |  | - |  |  |  | 197 |  |  |  | - |  |  |  | 197 |  |  |  | 8% |
Fixed Income securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Government |  |  | - |  |  |  | - |  |  |  | 72 |  |  |  | 72 |  |  |  | 3% |
Corporate |  |  | - |  |  |  | - |  |  |  | 56 |  |  |  | 56 |  |  |  | 2% |
Other |  |  | - |  |  |  | 5 |  |  |  | - |  |  |  | 5 |  |  |  | - |
Mutual funds |  |  | - |  |  |  | 246 |  |  |  | - |  |  |  | 246 |  |  |  | 10% |
Other |  |  | - |  |  |  | - |  |  |  | 4 |  |  |  | 4 |  |  |  | - |
Open-ended investments measured at NAV (1) |  |  | 819 |  |  |  | - |  |  |  | - |  |  |  | 819 |  |  |  | 34% |
Common collective trusts measured at NAV (2) |  |  | 409 |  |  |  | - |  |  |  | - |  |  |  | 409 |  |  |  | 18% |
Total |  | $ | 1,228 |  |  | $ | 1,048 |  |  | $ | 132 |  |  | $ | 2,408 |  |  |  | 100% |

(1) NAV investments are open-ended registered and non-registered mutual funds, collective investment trusts, or pooled funds. NAV’s are calculated daily and the funds honor subscription and redemption activity regularly.

(2) The common collective trusts are private funds valued at NAV. The NAVs are calculated based on bid prices of the underlying securities. Since the prices are not published to external sources, NAV is used as a practical expedient. Certain funds invest primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honor subscription and redemption activity regularly.

Refer to note 13 for more information on the fair value hierarchy and inputs used to measure fair value.

Post-Retirement Benefit Plans

There are no assets set aside to pay for the Canadian post-retirement benefit plans. As is common in Canada, post-retirement health benefits are paid from general accounts as required.

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Investments in Emera

As at December 31, 2018 and 2017, the assets related to the pension funds and post-retirement benefit plans do not hold any material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities.

Cash Flows

The following table shows the expected cash flows for defined benefit pension and other post-retirement benefit plans:

millions of Canadian dollars |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Expected employer contributions |  |  |  |  |  |  |  |
2019 |  | $ | 53 |  |  | $ | 22 |
Expected benefit payments |  |  |  |  |  |  |  |
2019 |  |  | 149 |  |  |  | 24 |
2020 |  |  | 152 |  |  |  | 25 |
2021 |  |  | 162 |  |  |  | 25 |
2022 |  |  | 169 |  |  |  | 25 |
2023 |  |  | 175 |  |  |  | 26 |
2024 – 2028 |  |  | 988 |  |  |  | 127 |

Assumptions

The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans:

|  | 2018 |  |  | 2017 |
(weighted average assumptions) |  | Defined benefit pension plans |  |  | Non-pension benefit plans |  |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Benefit obligation – December 31: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  |  | 4.05 % |  |  |  | 4.30 % |  |  |  | 3.55 % |  |  |  | 3.65 % |
Rate of compensation increase |  |  | 3.30 % |  |  |  | 3.67 % |  |  |  | 3.12 % |  |  |  | 3.28 % |
Health care trend - initial (next year) |  |  | - |  |  |  | 6.39 % |  |  |  | - |  |  |  | 6.65 % |
- ultimate |  |  | - |  |  |  | 4.45 % |  |  |  | - |  |  |  | 4.45 % |
- year ultimate reached |  |  | - |  |  |  | 2035 |  |  |  | - |  |  |  | 2036 |
Benefit cost for year ended December 31: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount rate |  |  | 3.55 % |  |  |  | 3.65 % |  |  |  | 3.96 % |  |  |  | 4.18 % |
Expected long-term return on plan assets |  |  | 6.38 % |  |  |  | 3.73 % |  |  |  | 6.29 % |  |  |  | 6.08 % |
Rate of compensation increase |  |  | 3.12 % |  |  |  | 3.28 % |  |  |  | 2.82 % |  |  |  | 2.54 % |
Health care trend - initial (current year) |  |  | - |  |  |  | 6.65 % |  |  |  | - |  |  |  | 6.78 % |
- ultimate |  |  | - |  |  |  | 4.45 % |  |  |  | - |  |  |  | 4.45 % |
- year ultimate reached |  |  | - |  |  |  | 2036 |  |  |  | - |  |  |  | 2035 |

Figures shown are weighted averages. Actual assumptions used differ by plan.

The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan.

The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated cash flows from the pension plan.

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Sensitivity Analysis for Non-Pension Benefits Plans

The health care cost trend significantly influences the amounts presented for health care plans. An increase or decrease of one percentage point of the assumed health care cost trend would have had the following impact in 2018:

millions of Canadian dollars |  | Increase |  |  | Decrease |
Service cost and interest cost |  |  | $ 1 |  |  | $ | (1) |
Accumulated post-retirement benefit obligation, December 31 |  |  | 17 |  |  |  | (15) |

Sensitivity Analysis for Defined Benefit Pension Plans

The impact on the 2018 benefit cost of a 25 basis point change in the discount rate and asset return assumptions is as follows:

millions of Canadian dollars |  | Increase |  |  | Decrease |
Discount rate assumption |  | $ | (9) |  |  | $ | 9 |
Asset rate assumption |  |  | (6) |  |  |  | 6 |

Amounts to be Amortized in the Next Fiscal Year

The following table shows the amounts from the AOCL and regulatory assets, which are expected to be recognized as part of the net periodic benefit cost in fiscal 2019:

millions of Canadian dollars |  | Defined benefit pension plans |  |  | Non-pension benefit plans |
Actuarial gains (losses) |  |  | $ (15) |  |  | $ | (1) |
Past service gains |  |  | 1 |  |  |  | 6 |
Regulatory assets |  |  | (16) |  |  |  | 2 |
Total |  |  | $ (30) |  |  | $ | 7 |

Defined Contribution Plan

Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2018 was $31 million (2017 – $23 million).

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20. NET INVESTMENT IN DIRECT FINANCING LEASE

Emera’s net investment in direct financing lease primarily relates to Brunswick Pipeline. The agreement meets the definition of a direct financing capital lease for accounting purposes. The net investment in direct financing lease consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. Net investment in direct financing lease consists of the following:

As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |
Total minimum lease payments to be received |  | $ | 1,066 |  |  | $ | 1,126 |
Less: amounts representing estimated executory costs |  |  | (201) |  |  |  | (211) |
Minimum lease payments receivable |  | $ | 865 |  |  | $ | 915 |
Estimated residual value of leased property (unguaranteed) |  |  | 183 |  |  |  | 183 |
Less: unearned finance lease income |  |  | (564) |  |  |  | (609) |
Net investment in direct financing lease |  | $ | 484 |  |  | $ | 489 |
Principal due within one year (included in Receivables and other current assets) |  |  | 9 |  |  |  | 8 |
Net investment in direct financing lease – long-term |  | $ | 475 |  |  | $ | 481 |

Future minimum lease payments to be received for the next five years:

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2019 |  |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |
Minimum lease payments to be received |  | $ | 65 |  |  | $ | 65 |  |  | $ | 65 |  |  | $ | 65 |  |  | $ | 64 |
Less: amounts representing estimated executory costs |  |  | (12) |  |  |  | (12) |  |  |  | (12) |  |  |  | (12) |  |  |  | (12) |
Minimum lease payments receivable |  | $ | 53 |  |  | $ | 53 |  |  | $ | 53 |  |  | $ | 53 |  |  | $ | 52 |

21. GOODWILL

The change in goodwill for the year ended December 31 is due to the following:

millions of Canadian dollars |  | 2018 |  |  | 2017 |
Balance, January 1 |  | $ | 5,805 |  |  | $ | 6,213 |
Change in foreign exchange rate |  |  | 508 |  |  |  | (408) |
Balance, December 31 |  | $ | 6,313 |  |  | $ | 5,805 |

Goodwill on Emera’s Consolidated Balance Sheets relates to the acquisitions of TECO Energy, Emera Maine and GBPC. Goodwill is subject to an annual assessment for impairment at the reporting unit level. Emera’s reporting units with goodwill are Tampa Electric, PGS, New Mexico Gas, Emera Maine and GBPC.

A qualitative impairment assessment was performed for Tampa Electric, PGS, New Mexico Gas, Emera Maine and GBPC, concluding that the fair value of the reporting units exceeded their respective carrying values, and as such, no quantitative assessments were performed and no impairment charges were recognized.

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22. SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of the following:

millions of Canadian dollars |  | 2018 |  |  | Weighted average interest rate |  |  | 2017 |  |  | Weighted average interest rate |
TECO Finance |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advances on revolving credit and term facilities |  | $ | 805 |  |  |  | 3.43 % |  |  | $ | 820 |  |  |  | 2.58 % |
Tampa Electric Company |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advances on accounts receivable and revolving credit facilities |  |  | 302 |  |  |  | 3.10 % |  |  |  | 382 |  |  |  | 2.07 % |
NMGC |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Advances on revolving credit facilities |  |  | 79 |  |  |  | 3.40 % |  |  |  | 38 |  |  |  | 2.47 % |
NSPI |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Bank indebtedness |  |  | - |  |  |  | - % |  |  |  | 1 |  |  |  | - % |
Short-Term debt |  | $ | 1,186 |  |  |  |  |  |  | $ | 1,241 |  |  |  |  |

The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:

millions of Canadian dollars |  | Maturity |  |  | 2018 |  |  | 2017 |
TECO Energy/TECO Finance - term credit facility |  |  | 2019 |  |  | $ | 682 |  |  | $ | 502 |
TECO Energy/TECO Finance - revolving credit facility |  |  | 2022 |  |  |  | 546 |  |  |  | 376 |
Tampa Electric Company - revolving credit facility |  |  | 2022 |  |  |  | 443 |  |  |  | 408 |
Tampa Electric Company - accounts receivable revolving credit facility |  |  | 2021 |  |  |  | 205 |  |  |  | 188 |
Tampa Electric Company - term loan |  |  | 2018 |  |  |  | - |  |  |  | 377 |
NMGC - revolving credit facility |  |  | 2022 |  |  |  | 171 |  |  |  | 157 |
GBPC - revolving credit facility |  |  | 2019 |  |  |  | 18 |  |  |  | 16 |
Total |  |  |  |  |  |  | 2,065 |  |  |  | 2,024 |
Less: |  |  |  |  |  |  |  |  |  |  |  |
Advances under revolving credit and term facilities |  |  |  |  |  |  | 1,186 |  |  |  | 1,241 |
Letters of credit issued within the credit facilities |  |  |  |  |  |  | 3 |  |  |  | 3 |
Total advances under available facilities |  |  |  |  |  |  | 1,189 |  |  |  | 1,244 |
Available capacity under existing agreements |  |  |  |  |  | $ | 876 |  |  | $ | 780 |

The weighted average interest rate on outstanding short-term debt at December 31, 2018 was 3.34 per cent (2017 – 2.42 per cent).

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Recent Financing Activity

Emera Florida and New Mexico

On October 11, 2018, TEC repaid a $300 million USD 1-year term credit facility using proceeds from a senior note issuance. Refer to note 24.

On March 23, 2018, TEC extended the maturity date of its $150 million USD accounts receivable collateralized borrowing facility from March 23, 2018 to March 22, 2021. There were no other changes in commercial terms.

On March 7, 2018, TECO Energy/Finance increased its $300 million USD revolving credit facility by $100 million USD to $400 million USD. There were no other changes in commercial terms.

On March 7, 2018, TECO Energy/Finance increased its $400 million USD term bank credit facility by $100 million USD to $500 million USD, and extended the maturity date to March 8, 2019. There were no other changes in commercial terms.

23. OTHER CURRENT LIABILITIES

Other current liabilities consisted of the following:

As at millions of Canadian dollars |  | December 31 2018 |  |  | December 31 2017 |
Accrued charges |  | $ | 154 |  |  | $ | 134 |
Accrued interest on long-term debt |  |  | 93 |  |  |  | 78 |
Pension and post-retirement liabilities (note 19) |  |  | 31 |  |  |  | 41 |
Sales and other taxes payable |  |  | 9 |  |  |  | 11 |
Emission credits obligations (1) |  |  | 8 |  |  |  | 21 |
Income tax payable |  |  | 6 |  |  |  | 1 |
Other |  |  | 127 |  |  |  | 64 |
|  | $ | 428 |  |  | $ | 350 |

(1) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory (note 11) when purchased and subsequently applied against the emission liabilities at the end of each compliance period.

24. LONG-TERM DEBT

Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included are certain bankers’ acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year.

Long-term debt as at December 31, 2018, consisted of the following:

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|  | Weighted average interest rate (1) |  |  |  |  |  |  |  |  |  |
millions of Canadian dollars |  | 2018 |  |  | 2017 |  |  | Maturity |  |  | 2018 |  |  | 2017 |
Emera |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Bankers acceptances, LIBOR loans |  |  | Variable |  |  |  | Variable |  |  |  | 2020 |  |  | $ | 339 |  |  | $ | 133 |
Unsecured fixed rate notes |  |  | 3.50% |  |  |  | 3.50% |  |  |  | 2019 - 2023 |  |  |  | 725 |  |  |  | 725 |
Fixed to floating subordinated notes (USD) |  |  | 6.75% |  |  |  | 6.75% |  |  |  | 2076 |  |  |  | 1,637 |  |  |  | 1,505 |
|  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 2,701 |  |  | $ | 2,363 |
Emera US Finance LP |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unsecured senior notes (USD) |  |  | 3.60% |  |  |  | 3.60% |  |  |  | 2019 - 2046 |  |  | $ | 4,434 |  |  | $ | 4,077 |
TECO Finance (2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Variable rate notes (USD) |  |  |  |  |  |  | Variable |  |  |  | 2018 |  |  | $ | - |  |  | $ | 314 |
Fixed rate notes and bonds (USD) |  |  | 5.15% |  |  |  | 5.15% |  |  |  | 2020 |  |  |  | 409 |  |  |  | 376 |
|  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 409 |  |  | $ | 690 |
Tampa Electric (3) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) |  |  | 4.64% |  |  |  | 4.75% |  |  |  | 2021 - 2049 |  |  | $ | 3,126 |  |  | $ | 2,410 |
PGS |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) |  |  | 4.66% |  |  |  | 5.06% |  |  |  | 2021 -2049 |  |  | $ | 425 |  |  | $ | 328 |
NMGC |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) |  |  | 4.53% |  |  |  | 4.53% |  |  |  | 2021 - 2026 |  |  | $ | 368 |  |  | $ | 339 |
NMGI |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate notes and bonds (USD) |  |  | 3.41% |  |  |  | 3.41% |  |  |  | 2019 - 2024 |  |  | $ | 273 |  |  | $ | 251 |
NSPI |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Discount notes |  |  | Variable |  |  |  | Variable |  |  |  | 2023 |  |  | $ | 516 |  |  | $ | 364 |
Medium term fixed rate notes |  |  | 5.73% |  |  |  | 5.73% |  |  |  | 2025 - 2097 |  |  |  | 1,965 |  |  |  | 1,965 |
Fixed rate debenture |  |  | 9.75% |  |  |  | 9.75% |  |  |  | 2019 |  |  |  | 95 |  |  |  | 95 |
|  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 2,576 |  |  | $ | 2,424 |
Emera Maine |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
LIBOR loans and demand loans |  |  | Variable |  |  |  | Variable |  |  |  | 2023 |  |  | $ | 28 |  |  | $ | 51 |
Secured fixed rate mortgage bonds (USD) |  |  | 9.74% |  |  |  | 9.74% |  |  |  | 2020 - 2022 |  |  |  | 68 |  |  |  | 63 |
Unsecured senior fixed rate notes (USD) |  |  | 4.23% |  |  |  | 4.15% |  |  |  | 2022 - 2048 |  |  |  | 382 |  |  |  | 294 |
|  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 478 |  |  | $ | 408 |
EBP |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Senior secured credit facility |  |  | 3.08% |  |  |  | 3.08% |  |  |  | 2022 |  |  | $ | 248 |  |  | $ | 248 |
GBPC |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Amortizing fixed rate notes (USD) |  |  | 3.83% |  |  |  | 3.77% |  |  |  | 2021 - 2022 |  |  | $ | 114 |  |  | $ | 78 |
Senior notes (USD) |  |  | 7.07% |  |  |  | 7.07% |  |  |  | 2020 - 2023 |  |  |  | 68 |  |  |  | 88 |
|  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 182 |  |  | $ | 166 |
ICDU |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate note (USD) |  |  | 4.00% |  |  |  | - |  |  |  | 2023 |  |  | $ | 24 |  |  | $ | - |
BLPC & ECI |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Secured senior notes (USD) |  |  | Variable |  |  |  | Variable |  |  |  | 2021 |  |  |  | 159 |  |  |  | 168 |
Secured fixed rate senior notes (4) |  |  | 4.74% |  |  |  | 5.06% |  |  |  | 2020 - 2035 |  |  | $ | 99 |  |  | $ | 76 |
|  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 258 |  |  | $ | 244 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fair market value adjustment - TECO Energy acquisition (5) |  |  |  |  |  |  |  |  |  |  | $ | 22 |  |  | $ | 31 |
Debt issuance costs |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (113) |  |  |  | (98) |
Amount due within one year |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1,119) |  |  |  | (741) |
|  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (1,210) |  |  | $ | (808) |
Long-Term Debt |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 14,292 |  |  | $ | 13,140 |

(1) Weighted average interest rate of fixed rate long-term debt.

(2) TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities.

(3) A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.

(4) Notes are issued and payable in either USD, BBD or East Caribbean Dollar (XCD).

(5) On acquisition of TECO Energy, Emera recorded a fair market value adjustment on the unregulated long-term debt acquired. The fair market value adjustment is amortized over the remaining term of the debt.

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The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:

millions of Canadian dollars |  | Maturity |  |  | 2018 |  |  | 2017 |
Emera – revolving credit facility (1) |  |  | June 2020 |  |  | $ | 900 |  |  | $ | 900 |
NSPI - revolving credit facility (1) |  |  | October 2023 |  |  |  | 600 |  |  |  | 600 |
Emera Maine – revolving credit facility |  |  | February 2023 |  |  |  | 109 |  |  |  | 100 |
BLPC – revolving credit facility |  |  | 2021 - 2022 |  |  |  | 26 |  |  |  | 24 |
Total |  |  |  |  |  |  | 1,635 |  |  |  | 1,624 |
Less: |  |  |  |  |  |  |  |  |  |  |  |
Borrowings under credit facilities |  |  |  |  |  |  | 899 |  |  |  | 598 |
Letters of credit issued inside credit facilities |  |  |  |  |  |  | 77 |  |  |  | 44 |
Use of available facilities |  |  |  |  |  |  | 976 |  |  |  | 642 |
Available capacity under existing agreements |  |  |  |  |  | $ | 659 |  |  | $ | 982 |

(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million.

Debt Covenants

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements. Emera’s significant covenants are listed below:

|  | Financial Covenant |  | Requirement |  | As at December 31, 2018
Emera |  |  |  |  |  |
Syndicated credit facilities |  | Debt to capital ratio |  | Less than or equal to 0.70 to 1 |  | 0.60 : 1

Recent Financing Activity

Emera

On May 16, 2018, Emera filed a $750 million debt and preferred equity shelf prospectus, providing the Company with access to raise long-term debt and preferred equity. On May 31, 2018, preferred shares were issued under this base shelf prospectus for gross proceeds of $300 million (refer to note 27). As at December 31, 2018 the Company has $450 million available for issuance under this prospectus, which expires on June 16, 2020.

Emera Florida and New Mexico

On October 4, 2018, TEC completed a $375 million USD 30-year senior notes issuance. The notes bear interest at a rate of 4.45 per cent and have a maturity date of June 15, 2049. Proceeds from this issuance were used to repay a $300 million USD 1-year term credit facility. Refer to note 22.

On June 7, 2018, TEC completed a $350 million USD 30-year senior notes issuance. The notes bear interest at a rate of 4.30 per cent and maturity date of June 15, 2048.

On April 10, 2018, TECO Energy/Finance repaid a $250 million USD note upon maturity. The note was repaid using funds from existing credit facilities and cash on hand.

NSPI

On October 31, 2018, NSPI amended its operating credit facility to extend the maturity from October 2021 to October 2023. There were no other changes in commercial terms.

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Emera Maine

On November 15, 2018, Emera Maine completed a $50 million USD 30-year senior notes issuance. The notes bear interest at a rate of 4.71 per cent and will mature on November 15, 2048. Proceeds from this issuance were used for general corporate purposes.

On February 28, 2018, Emera Maine extended the maturity date of its $80 million USD operating credit facility from September 25, 2019 to February 28, 2023. There were no other changes in commercial terms.

ECI

On January 12, 2018, a wholly owned indirect subsidiary of ECI entered into a five year $18 million Bahamian dollar loan agreement with an interest rate of 4.00 per cent and maturity date of January 12, 2023.

EBP

On October 31, 2018, Emera Brunswick Pipeline amended its Credit Agreement to extend the maturity from February 2021 to February 2022. There were no other changes in commercial terms.

Long-Term Debt Maturities

As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follows:

millions of Canadian dollars |  | 2019 |  |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | Thereafter |  |  | Total |
Emera |  | $ | 225 |  |  | $ | 339 |  |  | $ | - |  |  | $ | - |  |  | $ | 500 |  |  | $ | 1,637 |  |  | $ | 2,701 |
Emera US Finance LP |  |  | 682 |  |  |  | - |  |  |  | 1,023 |  |  |  | - |  |  |  | - |  |  |  | 2,729 |  |  |  | 4,434 |
TECO Finance |  |  | - |  |  |  | 409 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 409 |
Tampa Electric |  |  | - |  |  |  | - |  |  |  | 315 |  |  |  | 307 |  |  |  | - |  |  |  | 2,504 |  |  |  | 3,126 |
PGS |  |  | - |  |  |  | - |  |  |  | 64 |  |  |  | 34 |  |  |  | - |  |  |  | 327 |  |  |  | 425 |
NMGC |  |  | - |  |  |  | - |  |  |  | 273 |  |  |  | - |  |  |  | - |  |  |  | 95 |  |  |  | 368 |
NMGI |  |  | 69 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 204 |  |  |  | 273 |
NSPI |  |  | 95 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 516 |  |  |  | 1,965 |  |  |  | 2,576 |
Emera Maine |  |  | - |  |  |  | 41 |  |  |  | - |  |  |  | 123 |  |  |  | 28 |  |  |  | 286 |  |  |  | 478 |
EBP |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 248 |  |  |  | - |  |  |  | - |  |  |  | 248 |
GBPC |  |  | 17 |  |  |  | 50 |  |  |  | 37 |  |  |  | 33 |  |  |  | 45 |  |  |  | - |  |  |  | 182 |
ICDU |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 24 |  |  |  | - |  |  |  | 24 |
BLPC & ECI |  |  | 31 |  |  |  | 59 |  |  |  | 30 |  |  |  | 13 |  |  |  | 25 |  |  |  | 100 |  |  |  | 258 |
Total |  | $ | 1,119 |  |  | $ | 898 |  |  | $ | 1,742 |  |  | $ | 758 |  |  | $ | 1,138 |  |  | $ | 9,847 |  |  | $ | 15,502 |

25. ASSET RETIREMENT OBLIGATIONS

AROs mostly relate to the reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the fair value of any related ARO cannot be made.

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The change in ARO for the years ended December 31 is as follows:

millions of Canadian dollars |  | 2018 |  |  | 2017 |
Balance, January 1 |  | $ | 172 |  |  | $ | 170 |
Additions (1) |  |  | 25 |  |  |  | 2 |
Liabilities settled |  |  | (2) |  |  |  | (3) |
Accretion included in depreciation expense |  |  | 6 |  |  |  | 6 |
Other |  |  | (1) |  |  |  | 1 |
Change in foreign exchange rate |  |  | 5 |  |  |  | (4) |
Balance, December 31 |  | $ | 205 |  |  | $ | 172 |

(1) Tampa Electric produces ash and other by-products, collectively known as CCRs, at its Big Bend and Polk power stations. The 2018 additions to ARO are to achieve compliance with the EPA’s CCR rule, which contains design and operating standards for CCR management units. Tampa Electric submitted a petition to the FPSC in December 2018 for recovery of costs associated with the ongoing project and the petition is currently under review.

26. COMMITMENTS AND CONTINGENCIES

A. Commitments

As at December 31, 2018, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and AROs) for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars |  | 2019 |  |  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | Thereafter |  |  | Total |
Purchased power (1) |  | $ | 204 |  |  | $ | 203 |  |  | $ | 209 |  |  | $ | 208 |  |  | $ | 209 |  |  | $ | 2,194 |  |  | $ | 3,227 |
Transportation (2) (3) |  |  | 569 |  |  |  | 347 |  |  |  | 255 |  |  |  | 215 |  |  |  | 170 |  |  |  | 1,492 |  |  |  | 3,048 |
Fuel and gas supply |  |  | 642 |  |  |  | 237 |  |  |  | 49 |  |  |  | 7 |  |  |  | 3 |  |  |  | - |  |  |  | 938 |
Capital projects (4) |  |  | 524 |  |  |  | 147 |  |  |  | 45 |  |  |  | 11 |  |  |  | 3 |  |  |  | 8 |  |  |  | 738 |
Long-term service agreements (5) (6) |  |  | 110 |  |  |  | 67 |  |  |  | 42 |  |  |  | 30 |  |  |  | 33 |  |  |  | 246 |  |  |  | 528 |
Equity investment commitments (7) |  |  | - |  |  |  | 190 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 190 |
Leases and other (8) |  |  | 18 |  |  |  | 15 |  |  |  | 10 |  |  |  | 9 |  |  |  | 7 |  |  |  | 75 |  |  |  | 134 |
Demand side management |  |  | 44 |  |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 45 |
|  | $ | 2,111 |  |  | $ | 1,207 |  |  | $ | 610 |  |  | $ | 480 |  |  | $ | 425 |  |  | $ | 4,015 |  |  | $ | 8,848 |

(1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.

(2) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.

(3) Includes $82 million related to NEGG transportation capacity ($5 million in 2019; $5 million in 2020; $5 million in 2021; $4 million in 2022; $4 million in 2023 and $59 million thereafter). On completion of the sale of the NEGG facilities, the remaining future contractual obligations will be transferred to the buyer. Refer to note 17 for additional information.

(4) Includes $439 million of commitments related to Tampa Electric’s solar and Big Bend Power Station modernization projects.

(5) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(6) Includes $248 million related to various long-term service agreements NEGG has entered into for maintenance of certain generating equipment ($46 million in 2019; $9 million in 2020; $24 million in 2021; $16 million in 2022; $16 million in 2023 and $137 million thereafter). On completion of the sale of the NEGG facilities, the remaining future contractual obligations will be transferred to the buyer. Refer to note 17 for additional information.

(7) Emera has a commitment to make equity contributions to the Labrador Island Link Limited Partnership.

(8) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

NSPI has a contractual obligation to pay NSPML for the use of the Maritime Link over approximately 37 years. In January 2018, NSPI started paying the UARB approved interim assessment payments and as of December 31, 2018, $96 million has been paid to NSPML. The UARB approved payment for 2019 is $111 million and is subject to a $10 million holdback. Refer to note 14 for additional information. After 2019, the timing of and amounts payable to NSPML will be subject to regulatory filings with the UARB, with expected filings in 2019 and 2020.

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B. Legal Proceedings

Emera Florida and New Mexico

TECO Guatemala Holdings (“TGH”)

In 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (“Guatemala”) under the Dominican Republic Central America – United States Free Trade Agreement, issued an award in the case (“the Award”). The ICSID Tribunal unanimously found in favour of TGH and awarded damages to TGH of approximately $21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus two per cent. This award was upheld in subsequent annulment proceedings in 2016 and, in addition, TGH’s application for partial annulment of the award was granted, and Guatemala was ordered to pay certain costs relating to the annulment proceedings. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as well as additional interest on the $21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding.

On September 23, 2016, TGH filed a request for resubmission to arbitration. A new tribunal was constituted and the matter has been fully briefed. A hearing is scheduled for March 2019 and a decision is expected from the tribunal in 2020. In addition, TGH has sued Guatemala in Washington, D.C. court to enforce the $21 million USD owing. Guatemala’s motion to dismiss the enforcement action was denied. The parties are in the process of filing motions on the matter. Results to date do not reflect any benefit.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“PRP”) for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as at December 31, 2018, TEC has estimated its financial liability to be $38 million ($28 million USD), primarily at PGS. This estimate assumes that other involved PRPs are credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are believed to be currently credit-worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings.

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Emera Maine

From 2011 to 2016, four separate complaints were filed with the FERC to challenge the base ROE under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”).

| ● | Complaint I, filed by a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users, was remanded to the FERC by the US Court of Appeals in 2017 for further proceedings. No reserve has been made with respect to Complaint I due to uncertainty of the outcome.

| ● | Complaints II and III (the “ENE” and “MA AG II” cases), brought by a group of consumer advocates and by a group of state commissions, state public advocates and end users respectively, have been joined together and are presently pending before the FERC. Emera Maine has recorded a reserve of approximately $4 million USD for these cases. These reserves have been recorded as “Regulatory liabilities” on the Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Consolidated Statements of Income. The reserve was calculated based on Emera Maine’s best estimate of the probable outcome.

| ● | Complaint IV was filed by the Eastern Massachusetts Consumer Owned Systems (“EMCOS”). On March 27, 2018, a FERC Administrative Law Judge issued an Initial Decision concluding that the currently-filed base ROE of 10.57 per cent, which with incentive adders may reach a maximum ROE of 11.74 per cent, is not unjust and unreasonable. This decision was appealed to the FERC. No reserve has been made in relation to Complaint IV due to the uncertainty of the final outcome.

On October 16, 2018, the FERC issued an order that addressed all four complaint proceedings. The FERC order proposed a new methodology to set ROEs. Based on the new methodology, the FERC’s preliminary finding was a 10.41 per cent base ROE for the ISO-NE OATT. The FERC has permitted parties to comment on the new methodology and its application to the four pending complaint proceedings. No new or additional reserves have been made with respect to all four pending complaints due to uncertainty.

Other Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

C. Principal Financial Risks and Uncertainties

Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and fair value measurements are discussed in note 12 and note 13.

Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management.

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Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results.

Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and uses foreign currency derivative instruments to hedge specific transactions. The Company may enter into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams and capital expenditures. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI.

Liquidity and Capital Market Risk

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, select asset sales, short-term credit facilities, and ongoing access to capital markets. Cash flows generated from the sale of select assets are dependent on the market for the assets, acceptable pricing and the timing of the close of any sales. The Company reasonably expects liquidity sources to exceed capital needs.

Emera’s access to capital and cost of borrowing is subject to a number of risk factors including financial market conditions and ratings assigned by credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in property, plant and equipment. Emera is subject to risk with changes in interest rates that could have an adverse effect on the cost of financing. Inability to access to cost-effective capital could have a material impact on Emera’s ability to fund its growth plan.

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, and liquidity. A decrease in a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations. Emera manages this risk by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings.

The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation, preferred share units and deferred share units.

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Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives.

Commodity Price Risk

A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results.

D. Guarantees and Letters of Credit

Emera has several significant guarantees and letters of credit on behalf of third parties outstanding. The following guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2018:

TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $45 million USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which is expected to terminate on January 1, 2022. In the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $27 million USD.

The Company has standby letters of credit and surety bonds in the amount of $67 million USD to third parties that have extended credit to Emera and its subsidiaries. These letters of credit and surety bonds typically have a one year term and are renewed annually as required.

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Emera Reinsurance Limited has issued a standby letter of credit to secure its obligations under reinsurance agreements. The letter of credit expires in February 2019 and is renewed annually. The amount committed as of December 31, 2018 was $6 million USD.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The letter of credit expires in June 2019 and is renewed annually. The amount committed as at December 31, 2018 was $49 million.

Collaborative Arrangements

For the years ended December 31, 2018 and 2017, the Company has identified the following material collaborative arrangements:

Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in OM&G expenses. In 2018, NSPI recognized $19 million net expense (2017 - $18 million) in “Regulated fuel for generation and purchased power” and $2 million (2017 - $3 million) in OM&G.

27. CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

|  |  |  |  |  |  |  | December 31, 2018 |  |  | December 31, 2017 |
|  | Annual Dividend |  |  | Redemption |  |  | Issued and |  |  | Net |  |  | Issued and |  |  | Net |
|  | Per Share |  |  | Price per share |  |  | Outstanding |  |  | Proceeds |  |  | Outstanding |  |  | Proceeds |
Series A |  |  | $ 0.6388 |  |  | $ | 25.00 |  |  |  | 3,864,636 |  |  | $ | 95 |  |  |  | 3,864,636 |  |  | $ | 95 |
Series B |  |  | Floating |  |  | $ | 25.00 |  |  |  | 2,135,364 |  |  | $ | 52 |  |  |  | 2,135,364 |  |  | $ | 52 |
Series C |  |  | $ 1.1802 |  |  | $ | 25.00 |  |  |  | 10,000,000 |  |  | $ | 245 |  |  |  | 10,000,000 |  |  | $ | 245 |
Series E |  |  | $ 1.1250 |  |  | $ | 26.00 |  |  |  | 5,000,000 |  |  | $ | 122 |  |  |  | 5,000,000 |  |  | $ | 122 |
Series F |  |  | $ 1.0625 |  |  | $ | 25.00 |  |  |  | 8,000,000 |  |  | $ | 195 |  |  |  | 8,000,000 |  |  | $ | 195 |
Series H |  |  | $ 1.2250 |  |  | $ | 25.00 |  |  |  | 12,000,000 |  |  | $ | 295 |  |  |  | - |  |  | $ | - |
Total |  |  |  |  |  |  |  |  |  |  | 41,000,000 |  |  | $ | 1,004 |  |  |  | 29,000,000 |  |  | $ | 709 |

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Characteristics of the First Preferred Shares:

First Preferred Shares (1)(2) |  | Initial Yield (%) |  |  | Current Annual Dividend ($) |  |  | Minimum Reset Dividend Yield (%) |  |  | Earliest Redemption and/or Conversion Option Date |  |  | Redemption Value ($) |  |  | Right to Convert on a one for one basis |
Fixed rate reset (3)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Series A |  |  | 4.400 |  |  |  | 0.6388 |  |  |  | 1.84 |  |  |  | August 15, 2020 |  |  |  | 25.00 |  |  |  | Series B |
Series C (5) |  |  | 4.100 |  |  |  | 1.1802 |  |  |  | 2.65 |  |  |  | August 15, 2023 |  |  |  | 25.00 |  |  |  | Series D |
Series F |  |  | 4.250 |  |  |  | 1.0625 |  |  |  | 2.63 |  |  |  | February 15, 2020 |  |  |  | 25.00 |  |  |  | Series G |
Minimum rate reset (3)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Series B |  |  | 2.393 |  |  |  | Floating |  |  |  | 1.84 |  |  |  | August 15, 2020 |  |  |  | 25.00 |  |  |  | Series A |
Series H |  |  | 4.900 |  |  |  | 1.2250 |  |  |  | 4.90 |  |  |  | August 15, 2023 |  |  |  | 25.00 |  |  |  | Series I |
Perpetual fixed rate |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Series E (6) |  |  | 4.500 |  |  |  | 1.1250 |  |  |  |  |  |  |  |  |  |  |  | 26.00 |  |  |  |  |

(1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation.

(2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Preferred Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption.

(3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield (Series H annual reset rate must be a minimum of 4.90 per cent) and for Series B equals the Government of Treasury Bill Rate on the applicable reset date, plus 1.84 per cent.

(4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their Shares into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right to redeem the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years thereafter for cash, in whole or in part at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption and $25.50 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2018, February 15, 2020 and August 15, 2023, respectively. The reset dividend yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 per cent.

(5) The annual fixed dividend per share for First Preferred Shares, Series C was reset from $1.0250 to $1.1802 for the five-year period from and including August 15, 2018.

(6) First Preferred Shares, Series E are redeemable at $26.00 to August 15, 2019, decreasing $0.25 each year until August 15, 2022 and $25.00 per share thereafter.

First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends is deducted on the Consolidated Statements of Income before arriving at “Net earnings attributable to common shareholders” and is shown on the Consolidated Statement of Equity as a deduction from retained earnings.

The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.

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28. NON-CONTROLLING INTEREST IN SUBSIDIARIES

Non-controlling interest in subsidiaries consisted of the following:

As at |  | December 31 |  |  | December 31 |
millions of Canadian dollars |  | 2018 |  |  | 2017 |
Domlec |  | $ | 22 |  |  | $ | 21 |
Preferred shares of GBPC |  |  | 19 |  |  |  | 19 |
ICDU (1) |  |  | - |  |  |  | 52 |
|  | $ | 41 |  |  | $ | 92 |

(1) On January 15, 2018, Emera completed the acquisition of the minority shareholder common shares for total consideration of $35 million USD. This acquisition increases Emera’s indirect ownership interest to 100 per cent.

Preferred shares of GBPC:

Authorized:

20,000 non-voting cumulative redeemable variable perpetual preferred shares.

|  | 2018 |  |  | 2017 |
Issued and outstanding: |  | number of shares |  |  | millions of dollars |  |  | number of shares |  |  | millions of dollars |
Outstanding as at December 31 |  |  | 20,000 |  |  | $ | 19 |  |  |  | 20,000 |  |  | $ | 19 |

GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock:

The Preferred Stock is redeemable by GBPC, in whole at any time or in part from time to time, at $1,000 Bahamian per share plus accrued and unpaid dividends.

The Preferred Stock is entitled to a 7.25 per cent per annum fixed cumulative preferential dividend for years 2013 through 2016, 8.50 per cent per annum fixed cumulative preferential dividend for years 2017 through 2019 and 10.00 per cent per annum fixed cumulative preferential dividend after 2020, as and when declared by the Board of Directors, accruing from the date of issue.

The Preferred Shares rank behind all of GBPC’s current and future secured and unsecured debt with any of GBPC’s future preferred stock and ahead of all of GBPC’s current and future common stock.

29. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

For the |  | Year ended December 31 |
millions of Canadian dollars |  | 2018 |  |  | 2017 |
Changes in non-cash working capital: |  |  |  |  |  |  |  |
Inventory |  | $ | (44) |  |  | $ | 31 |
Receivables and other current assets |  |  | (144) |  |  |  | (154) |
Accounts payable |  |  | 59 |  |  |  | 3 |
Other current liabilities |  |  | 13 |  |  |  | 16 |
Total non-cash working capital |  | $ | (116) |  |  | $ | (104) |
Supplemental disclosure of cash paid: |  |  |  |  |  |  |  |
Interest |  | $ | 653 |  |  | $ | 689 |
Income taxes |  | $ | 33 |  |  | $ | 63 |
Supplemental disclosure of non-cash activities: |  |  |  |  |  |  |  |
Common share dividends reinvested |  | $ | 181 |  |  | $ | 166 |
Change in accrued capital expenditures |  | $ | (50) |  |  | $ | 13 |
Issuance of depository receipts |  | $ | 22 |  |  | $ | - |

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30. STOCK-BASED COMPENSATION

Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan

Eligible employees may participate in Emera’s Employee Common Share Purchase Plan to which employees make cash contributions of a minimum of $25 to a maximum of $8,000 per year for the purpose of purchasing common shares of Emera. The Company also contributes to the plan a percentage of the employees’ contributions. If an employee contributes any amount up to $3,000 to that employee’s plan account, the Company will contribute 20 per cent of that amount. When an employee contributes any amount over $3,000, up to the $8,000 maximum, the Company will contribute 10 per cent of that amount.

The plan allows the reinvestment of dividends. The maximum aggregate number of Emera common shares reserved for issuance under this plan is 4 million common shares. As at December 31, 2018, Emera is in compliance with this requirement.

Compensation cost for shares issued by Emera for the year ended December 31, 2018 under the Employee Common Share Purchase Plan was $1 million (2017 – $1 million) and is included in “OM&G” on the Consolidated Statements of Income.

The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”) or (“DRIP”), which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares.

Stock-Based Compensation Plans

Stock Option Plan

The Company has a stock option plan that grants options to senior management of the Company for a maximum term of ten years. The option price of the stock options is the closing market price of the stocks on the day before the option is granted. The maximum aggregate number of shares issuable under this plan is 11.7 million shares. As at December 31, 2018, Emera is in compliance with this requirement.

Stock options vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. If an option is not exercised within ten years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted.

Unless a stock option has expired, vested options may be exercised within the 24 months following the option holders date of retirement or termination for other than just cause, and within six months following the date of termination for just cause, resignation or death. If stock options are not exercised within such time, they expire.

The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis.

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The following table shows the weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted, for the year-ended December:

|  | 2018 |  |  | 2017 |
Weighted average fair value per option |  | $ | 1.70 |  |  | $ | 2.37 |
Expected term (1) |  |  | 6 years |  |  |  | 5 years |
Risk-free interest rate (2) |  |  | 2.13% |  |  |  | 1.22% |
Expected dividend yield (3) |  |  | 5.69% |  |  |  | 4.60% |
Expected volatility (4) |  |  | 13.71% |  |  |  | 14.41% |

(1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that the options are expected to be outstanding.

(2) Based on the Bank of Canada five-year government bond yields.

(3) Incorporates current dividend rates and historical dividend increase patterns.

(4) Estimated using the five-year historical volatility.

The following table summarizes stock option information for 2018:

|  | Total Options |  |  | Non-Vested Options(1) |
|  | Number of Options |  |  | Weighted average exercise price per share |  |  | Number of Options |  |  | Weighted average grant date fair-value |
Outstanding as at December 31, 2017 |  |  | 3,643,575 |  |  | $ | 39.42 |  |  |  | 1,739,650 |  |  | $ | 2.52 |
Granted |  |  | 627,600 |  |  |  | 39.93 |  |  |  | 627,600 |  |  |  | 1.70 |
Exercised |  |  | (23,800) |  |  |  | 24.98 |  |  |  | N/A |  |  |  | N/A |
Vested |  |  | N/A |  |  |  | N/A |  |  |  | (666,125) |  |  |  | 2.51 |
Forfeited |  |  | (11,700) |  |  |  | 45.10 |  |  |  | (11,700) |  |  |  | 2.54 |
Expired |  |  | (10,100) |  |  |  | 39.93 |  |  |  | (10,100) |  |  |  | 1.70 |
Options outstanding December 31, 2018 |  |  | 4,225,575 |  |  | $ | 39.56 |  |  |  | 1,679,325 |  |  | $ | 2.22 |
Options exercisable December 31, 2018 (2)(3) |  |  | 2,546,250 |  |  | $ | 37.15 |  |  |  |  |  |  |  |  |

(1) As at December 31, 2018, there was $5 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 2.2 years (2017 - $3 million, 2.5 years).

(2) As at December 31, 2018, the weighted average remaining term of vested options was 5.1 years with an aggregate intrinsic value of $18 million (2017 - 5.4 years, $22 million).

(3) As at December 31, 2018, the fair value of options that vested in the year was $2 million (2017 - $2 million).

Compensation cost recognized for stock options for the year ended December 31, 2018 was $1 million (2017 – $2 million), which is included in “Operating, maintenance and general” on the Consolidated Statements of Income.

As at December 31, 2018, cash received from option exercises was $1 million (2017 – $3 million). The total intrinsic value of options exercised for the year ended December 31, 2018 was $1 million (2017 – $2 million). The range of exercise prices for the options outstanding as at December 31, 2018 was $21.99 to $46.19 (2017 – $21.58 to $46.19).

Share Unit Plans

The Company has DSU and PSU plans and the liabilities are marked-to-market at the end of each period based on the common share price at the end of the period.

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Deferred Share Unit Plans

Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs, also referred to as DRIP. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price during the ten trading days ending on the tenth trading day prior to the payment date.

Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met.

When incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee (“MRCC”), payments may be made in the form of actual shares.

In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to recognize singular achievements or to achieve certain corporate objectives.

A summary of the activity related to employee and director DSUs for the year ended December 31, 2018 is presented in the following table:

|  | Employee DSU |  |  | Weighted Average Grant Date Fair Value |  |  | Director DSU |  |  | Weighted Average Grant Date Fair Value |
Outstanding as at December 31, 2017 |  |  | 751,600 |  |  | $ | 28.44 |  |  |  | 472,485 |  |  | $ | 35.33 |
Granted including DRIP |  |  | 90,549 |  |  |  | 38.72 |  |  |  | 101,676 |  |  |  | 43.93 |
Exercised |  |  | (5,040) |  |  |  | 30.15 |  |  |  | (10,640) |  |  |  | 25.31 |
Outstanding and exercisable as at December 31, 2018 |  |  | 837,109 |  |  | $ | 29.54 |  |  |  | 563,521 |  |  | $ | 37.07 |

Compensation cost recognized for employee and director DSU for the year ended December 31, 2018 was $2 million (2017 – $7 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2018 were $1 million (2017 – $2 million). The aggregate intrinsic value of the outstanding shares for the year ended December 31, 2018 was $37 million (2017 - $35 million).

77

Performance Share Unit Plan

Under the PSU plan, executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Dividend equivalents are awarded and paid in the form of additional PSUs, also referred to as DRIP. The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of termination, disability or death.

A summary of the activity related to employee PSUs for the year ended December 31, 2018 is presented in the following table:

|  | Employee PSU |  |  | Weighted Average Grant Date Fair Value |  |  | Aggregate intrinsic value |
Outstanding as at December 31, 2017 |  |  | 829,998 |  |  | $ | 43.41 |  |  | $ | 41.1 |
Granted including DRIP |  |  | 486,181 |  |  |  | 47.84 |  |  |  |  |
Exercised |  |  | (176,805) |  |  |  | 38.85 |  |  |  |  |
Forfeited |  |  | (12,260) |  |  |  | 44.88 |  |  |  |  |
Outstanding as at December 31, 2018 |  |  | 1,127,114 |  |  | $ | 46.02 |  |  | $ | 56.9 |

Compensation cost recognized for the PSU plan for the year ended December 31, 2018 was $14 million (2017 – $14 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2018 were $4 million (2017 – $4 million).

31. VARIABLE INTEREST ENTITIES

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. In Q2 2014, when the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment.

BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF.

The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

78

The following table provides information about Emera’s portion of material unconsolidated VIEs:

As at |  | December 31, 2018 |  |  | December 31, 2017 |
|  |  |  |  | Maximum |  |  |  |  |  | Maximum |
millions of Canadian dollars |  | Total assets |  |  | exposure to loss |  |  | Total assets |  |  | exposure to loss |
Unconsolidated VIEs in which Emera has variable interests |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NSPML (equity accounted) |  | $ | 545 |  |  | $ | 51 |  |  | $ | 510 |  |  | $ | 67 |

32. COMPARATIVE INFORMATION

These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

33. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 15, 2019, the date the financial statements were issued.

34. SUPPLEMENTAL FINANCIAL INFORMATION

On June 16, 2016, Emera US Finance LP, (in such capacity, the “Issuer”), issued $3.25 billion USD senior unsecured notes (“U.S. Notes”). The U.S. Notes are fully and unconditionally guaranteed, on a joint and several basis, by Emera (in such capacity, the “Parent Company”) and Emera US Holdings Inc. (in such capacity, the “Guarantor Subsidiaries”). Emera owns, directly or indirectly, all of the limited and general partnership interests in Emera US Finance LP.

The following condensed consolidated financial statements present the results of operations, financial position and cash flows of the Parent Company, Subsidiary Issuer, Guarantor Subsidiaries and all other Non-guarantor Subsidiaries independently and on a consolidated basis.

Our guarantors were not determined using geographic, service line or other similar criteria, and as a result, the “Parent”, “Subsidiary Issuer”, “Guarantor Subsidiaries” and “Non-guarantor Subsidiaries” columns each include portions of our domestic and international operations. Accordingly, this basis of presentation is not intended to present our financial condition, results of operations or cash flows for any purpose other than to comply with the specific requirements for guarantor reporting.

79

Emera Incorporated

Condensed Consolidated Statements of Income

millions of Canadian dollars |  | Parent |  |  | Subsidiary Issuer |  |  | Guarantor Subsidiaries |  |  | Non-guarantor Subsidiaries |  |  | Eliminations |  |  | Consolidated |
For the year ended December 31, 2018 |
Operating revenues |  | $ | - |  |  | $ | - |  |  | $ | 4,432 |  |  | $ | 2,146 |  |  | $ | (54) |  |  | $ | 6,524 |
Operating expenses |  |  | 45 |  |  |  | - |  |  |  | 3,468 |  |  |  | 1,665 |  |  |  | (52) |  |  |  | 5,126 |
Income (loss) from equity investments and subsidiaries |  |  | 801 |  |  |  | - |  |  |  | 3 |  |  |  | 150 |  |  |  | (800) |  |  |  | 154 |
Other income (expenses), net |  |  | 22 |  |  |  | - |  |  |  | 20 |  |  |  | (27) |  |  |  | (38) |  |  |  | (23) |
Interest expense, net (1) |  |  | 79 |  |  |  | (40) |  |  |  | 456 |  |  |  | 218 |  |  |  | - |  |  |  | 713 |
Income (loss) before provision for income taxes |  |  | 699 |  |  |  | 40 |  |  |  | 531 |  |  |  | 386 |  |  |  | (840) |  |  |  | 816 |
Income tax expense (recovery) |  |  | (47) |  |  |  | 9 |  |  |  | 64 |  |  |  | 43 |  |  |  | - |  |  |  | 69 |
Net income (loss) |  |  | 746 |  |  |  | 31 |  |  |  | 467 |  |  |  | 343 |  |  |  | (840) |  |  |  | 747 |
Non-controlling interest in subsidiaries |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (1) |  |  |  | 2 |  |  |  | 1 |
Preferred stock dividends |  |  | 36 |  |  |  | - |  |  |  | 38 |  |  |  | 4 |  |  |  | (42) |  |  |  | 36 |
Net income (loss) attributable to common shareholders |  | $ | 710 |  |  | $ | 31 |  |  | $ | 429 |  |  | $ | 340 |  |  | $ | (800) |  |  | $ | 710 |
Comprehensive income (loss) of Emera Incorporated |  | $ | 1,249 |  |  | $ | 56 |  |  | $ | 973 |  |  | $ | 439 |  |  | $ | (1,468) |  |  | $ | 1,249 |
For the year ended December 31, 2017 |
Operating revenues |  | $ | - |  |  | $ | - |  |  | $ | 4,274 |  |  | $ | 2,009 |  |  | $ | (57) |  |  | $ | 6,226 |
Operating expenses |  |  | 41 |  |  |  | - |  |  |  | 3,241 |  |  |  | 1,583 |  |  |  | (57) |  |  |  | 4,808 |
Income (loss) from equity investments and subsidiaries |  |  | 337 |  |  |  | - |  |  |  | 1 |  |  |  | 122 |  |  |  | (336) |  |  |  | 124 |
Other income (expenses), net |  |  | 38 |  |  |  | - |  |  |  | 15 |  |  |  | (46) |  |  |  | (32) |  |  |  | (25) |
Interest expense, net (1) |  |  | 84 |  |  |  | (40) |  |  |  | 451 |  |  |  | 203 |  |  |  | - |  |  |  | 698 |
Income (loss) before provision for income taxes |  |  | 250 |  |  |  | 40 |  |  |  | 598 |  |  |  | 299 |  |  |  | (368) |  |  |  | 819 |
Income tax expense (recovery) |  |  | (44) |  |  |  | 17 |  |  |  | 511 |  |  |  | 36 |  |  |  | - |  |  |  | 520 |
Net income (loss) |  |  | 294 |  |  |  | 23 |  |  |  | 87 |  |  |  | 263 |  |  |  | (368) |  |  |  | 299 |
Non-controlling interest in subsidiaries |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 1 |  |  |  | 4 |  |  |  | 5 |
Preferred stock dividends |  |  | 28 |  |  |  | - |  |  |  | 29 |  |  |  | 13 |  |  |  | (42) |  |  |  | 28 |
Net income (loss) attributable to common shareholders |  | $ | 266 |  |  | $ | 23 |  |  | $ | 58 |  |  | $ | 249 |  |  | $ | (330) |  |  | $ | 266 |
Comprehensive income (loss) of Emera Incorporated |  | $ | (6) |  |  | $ | 3 |  |  | $ | (291) |  |  | $ | 265 |  |  | $ | 23 |  |  | $ | (6) |
(1) Interest expense is net of interest revenue. |  |  |  |  |  |  |  |  |

80

Emera Incorporated

Condensed Consolidated Balance Sheets

millions of Canadian dollars |  | Parent |  |  | Subsidiary Issuer |  |  | Guarantor Subsidiaries |  |  | Non-guarantor Subsidiaries |  |  | Eliminations |  |  | Consolidated |
As at December 31, 2018 |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  | $ | 146 |  |  | $ | 67 |  |  |  | 1,767 |  |  | $ | 1,096 |  |  | $ | (244) |  |  | $ | 2,832 |
Property, plant and equipment |  |  | 24 |  |  |  | - |  |  |  | 13,745 |  |  |  | 4,946 |  |  |  | (3) |  |  |  | 18,712 |
Other assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory assets |  |  | - |  |  |  | - |  |  |  | 645 |  |  |  | 759 |  |  |  | - |  |  |  | 1,404 |
Goodwill |  |  | - |  |  |  | - |  |  |  | 6,208 |  |  |  | 105 |  |  |  | - |  |  |  | 6,313 |
Other long-term assets |  |  | 11,457 |  |  |  | 4,660 |  |  |  | 971 |  |  |  | 3,200 |  |  |  | (17,235) |  |  |  | 3,053 |
Total other assets |  |  | 11,457 |  |  |  | 4,660 |  |  |  | 7,824 |  |  |  | 4,064 |  |  |  | (17,235) |  |  |  | 10,770 |
Total assets |  | $ | 11,627 |  |  | $ | 4,727 |  |  | $ | 23,336 |  |  | $ | 10,106 |  |  | $ | (17,482) |  |  | $ | 32,314 |
Liabilities and Equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities |  | $ | 368 |  |  | $ | 695 |  |  | $ | 2,829 |  |  | $ | 926 |  |  | $ | (265) |  |  | $ | 4,553 |
Long-term liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  |  | 2,906 |  |  |  | 3,709 |  |  |  | 10,243 |  |  |  | 4,428 |  |  |  | (6,994) |  |  |  | 14,292 |
Deferred income taxes |  |  | - |  |  |  | 3 |  |  |  | 668 |  |  |  | 643 |  |  |  | 6 |  |  |  | 1,320 |
Regulatory liabilities |  |  | - |  |  |  | - |  |  |  | 2,118 |  |  |  | 241 |  |  |  | - |  |  |  | 2,359 |
Other long-term liabilities |  |  | 36 |  |  |  | - |  |  |  | 874 |  |  |  | 543 |  |  |  | (21) |  |  |  | 1,432 |
Total long-term liabilities |  |  | 2,942 |  |  |  | 3,712 |  |  |  | 13,903 |  |  |  | 5,855 |  |  |  | (7,009) |  |  |  | 19,403 |
Total Emera Incorporated equity |  |  | 8,317 |  |  |  | 320 |  |  |  | 6,604 |  |  |  | 3,303 |  |  |  | (10,227) |  |  |  | 8,317 |
Non-controlling interest in subsidiaries |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 22 |  |  |  | 19 |  |  |  | 41 |
Total equity |  |  | 8,317 |  |  |  | 320 |  |  |  | 6,604 |  |  |  | 3,325 |  |  |  | (10,208) |  |  |  | 8,358 |
Total liabilities and equity |  | $ | 11,627 |  |  | $ | 4,727 |  |  | $ | 23,336 |  |  | $ | 10,106 |  |  | $ | (17,482) |  |  | $ | 32,314 |
As at December 31, 2017 |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  | $ | 358 |  |  | $ | 30 |  |  |  | 1,420 |  |  | $ | 891 |  |  | $ | (173) |  |  | $ | 2,526 |
Property, plant and equipment |  |  | 17 |  |  |  | - |  |  |  | 12,258 |  |  |  | 4,720 |  |  |  | - |  |  |  | 16,995 |
Other assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory assets |  |  | - |  |  |  | - |  |  |  | 587 |  |  |  | 686 |  |  |  | - |  |  |  | 1,273 |
Goodwill |  |  | - |  |  |  | - |  |  |  | 5,709 |  |  |  | 96 |  |  |  | - |  |  |  | 5,805 |
Other long-term assets |  |  | 9,761 |  |  |  | 4,285 |  |  |  | 156 |  |  |  | 3,094 |  |  |  | (15,089) |  |  |  | 2,207 |
Total other assets |  |  | 9,761 |  |  |  | 4,285 |  |  |  | 6,452 |  |  |  | 3,876 |  |  |  | (15,089) |  |  |  | 9,285 |
Total assets |  | $ | 10,136 |  |  | $ | 4,315 |  |  | $ | 20,130 |  |  | $ | 9,487 |  |  | $ | (15,262) |  |  | $ | 28,806 |
Liabilities and Equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities |  | $ | 129 |  |  | $ | 12 |  |  | $ | 3,293 |  |  | $ | 714 |  |  | $ | (202) |  |  | $ | 3,946 |
Long-term liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt |  |  | 2,861 |  |  |  | 4,034 |  |  |  | 8,468 |  |  |  | 4,262 |  |  |  | (6,485) |  |  |  | 13,140 |
Deferred income taxes |  |  | - |  |  |  | 4 |  |  |  | 447 |  |  |  | 565 |  |  |  | 7 |  |  |  | 1,023 |
Regulatory liabilities |  |  | - |  |  |  | - |  |  |  | 1,888 |  |  |  | 354 |  |  |  | - |  |  |  | 2,242 |
Other long-term liabilities |  |  | 34 |  |  |  | - |  |  |  | 691 |  |  |  | 550 |  |  |  | (24) |  |  |  | 1,251 |
Total long-term liabilities |  |  | 2,895 |  |  |  | 4,038 |  |  |  | 11,494 |  |  |  | 5,731 |  |  |  | (6,502) |  |  |  | 17,656 |
Total Emera Incorporated equity |  |  | 7,112 |  |  |  | 265 |  |  |  | 5,343 |  |  |  | 2,970 |  |  |  | (8,578) |  |  |  | 7,112 |
Non-controlling interest in subsidiaries |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 72 |  |  |  | 20 |  |  |  | 92 |
Total equity |  |  | 7,112 |  |  |  | 265 |  |  |  | 5,343 |  |  |  | 3,042 |  |  |  | (8,558) |  |  |  | 7,204 |
Total liabilities and equity |  | $ | 10,136 |  |  | $ | 4,315 |  |  | $ | 20,130 |  |  | $ | 9,487 |  |  | $ | (15,262) |  |  | $ | 28,806 |

81

Emera Incorporated

Condensed Consolidated Statements of Cash Flows

millions of Canadian dollars |  | Parent |  |  | Subsidiary Issuer |  |  | Guarantor Subsidiaries |  |  | Non-guarantor Subsidiaries |  |  | Eliminations |  |  | Consolidated |
As at December 31, 2018 |
Net cash provided by (used in) by operating activities |  | $ | 191 |  |  | $ | 35 |  |  | $ | 1,266 |  |  | $ | 465 |  |  | $ | (267) |  |  | $ | 1,690 |
Investing activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (9) |  |  |  | - |  |  |  | (1,687) |  |  |  | (466) |  |  |  | - |  |  |  | (2,162) |
Net purchase of investments subject to significant influence |  |  | - |  |  |  |  |  |  |  | (16) |  |  |  | (33) |  |  |  | - |  |  |  | (49) |
Other investing activities |  |  | (489) |  |  |  | - |  |  |  | 3 |  |  |  | (65) |  |  |  | 572 |  |  |  | 21 |
Net cash provided by (used in) investing activities |  |  | (498) |  |  |  | - |  |  |  | (1,700) |  |  |  | (564) |  |  |  | 572 |  |  |  | (2,190) |
Financing activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in short-term debt, net |  |  | - |  |  |  | - |  |  |  | (162) |  |  |  | - |  |  |  | - |  |  |  | (162) |
Proceeds from long-term debt |  |  | - |  |  |  | - |  |  |  | 1,174 |  |  |  | 75 |  |  |  | (194) |  |  |  | 1,055 |
Retirement of long-term debt |  |  | - |  |  |  | - |  |  |  | (716) |  |  |  | (41) |  |  |  | - |  |  |  | (757) |
Net borrowings (repayments) under committed credit facilities |  |  | 136 |  |  |  | - |  |  |  | (103) |  |  |  | 178 |  |  |  | 110 |  |  |  | 321 |
Issuance of common and preferred stock |  |  | 301 |  |  |  | - |  |  |  | 319 |  |  |  | 127 |  |  |  | (446) |  |  |  | 301 |
Dividends paid |  |  | (382) |  |  |  | - |  |  |  | (37) |  |  |  | (311) |  |  |  | 348 |  |  |  | (382) |
Other financing activities |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 91 |  |  |  | (123) |  |  |  | (32) |
Net cash provided by (used in) financing activities |  |  | 55 |  |  |  | - |  |  |  | 475 |  |  |  | 119 |  |  |  | (305) |  |  |  | 344 |
Effect of exchange rate changes on cash, cash equivalents and restricted cash |  |  | (4) |  |  |  | 2 |  |  |  | 9 |  |  |  | 18 |  |  |  | - |  |  |  | 25 |
Net increase (decrease) in cash, cash equivalents and restricted cash |  |  | (256) |  |  |  | 37 |  |  |  | 50 |  |  |  | 38 |  |  |  | - |  |  |  | (131) |
Cash, cash equivalents and restricted cash, beginning of year |  |  | 276 |  |  |  | 21 |  |  |  | 54 |  |  |  | 152 |  |  |  | - |  |  |  | 503 |
Cash, cash equivalents and restricted cash, end of year |  | $ | 20 |  |  | $ | 58 |  |  | $ | 104 |  |  | $ | 190 |  |  | $ | - |  |  | $ | 372 |
As at December 31, 2017 |
Net cash provided by (used in) operating activities |  | $ | 195 |  |  | $ | 22 |  |  | $ | 658 |  |  | $ | 1,080 |  |  | $ | (762) |  |  | $ | 1,193 |
Investing activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Additions to property, plant and equipment |  |  | (5) |  |  |  | - |  |  |  | (1,031) |  |  |  | (480) |  |  |  | (13) |  |  |  | (1,529) |
Net purchase of investments subject to significant influence |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (213) |  |  |  | - |  |  |  | (213) |
Other investing activities |  |  | (742) |  |  |  | (26) |  |  |  | (5) |  |  |  | 1,852 |  |  |  | (1,098) |  |  |  | (19) |
Net cash provided by (used in) investing activities |  |  | (747) |  |  |  | (26) |  |  |  | (1,036) |  |  |  | 1,159 |  |  |  | (1,111) |  |  |  | (1,761) |
Financing activities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in short-term debt, net |  |  | - |  |  |  | - |  |  |  | 365 |  |  |  | (13) |  |  |  | - |  |  |  | 352 |
Proceeds from long-term debt |  |  | - |  |  |  | - |  |  |  | 147 |  |  |  | (31) |  |  |  | 13 |  |  |  | 129 |
Retirement of long-term debt |  |  | - |  |  |  | - |  |  |  | (413) |  |  |  | (55) |  |  |  | 15 |  |  |  | (453) |
Net borrowings (repayments) under committed credit facilities |  |  | (30) |  |  |  | - |  |  |  | 59 |  |  |  | 192 |  |  |  | 9 |  |  |  | 230 |
Issuance of common and preferred stock |  |  | 682 |  |  |  | - |  |  |  | 134 |  |  |  | (2,032) |  |  |  | 1,898 |  |  |  | 682 |
Dividends paid |  |  | (315) |  |  |  | - |  |  |  | (29) |  |  |  | (285) |  |  |  | 314 |  |  |  | (315) |
Other financing activities |  |  | 290 |  |  |  | - |  |  |  | 96 |  |  |  | (42) |  |  |  | (376) |  |  |  | (32) |
Net cash provided by (used in) financing activities |  |  | 627 |  |  |  | - |  |  |  | 359 |  |  |  | (2,266) |  |  |  | 1,873 |  |  |  | 593 |
Effect of exchange rate changes on cash, cash equivalents and restricted cash |  |  | 1 |  |  |  | (3) |  |  |  | 1 |  |  |  | (12) |  |  |  | - |  |  |  | (13) |
Net increase (decrease) in cash, cash equivalents and restricted cash |  |  | 76 |  |  |  | (7) |  |  |  | (18) |  |  |  | (39) |  |  |  | - |  |  |  | 12 |
Cash, cash equivalents and restricted cash, beginning of year |  |  | 200 |  |  |  | 28 |  |  |  | 72 |  |  |  | 191 |  |  |  | - |  |  |  | 491 |
Cash, cash equivalents and restricted cash, end of year |  | $ | 276 |  |  | $ | 21 |  |  | $ | 54 |  |  | $ | 152 |  |  | $ | - |  |  | $ | 503 |

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